PUBLIC SERVICE ENTERPRISE GROUP INC [PEG] Filings

10-K 1 pseg-20231231.htm 10-K pseg-20231231

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

——————————

FORM 10-K

(Mark One)

☒ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934

FOR THE FISCAL YEAR ENDED December 31, 2023

☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934

FOR THE TRANSITION PERIOD FROM TO


Commission File Number	Name of Registrant, Address, and Telephone Number			State or other jurisdiction of Incorporation	I.R.S. Employer Identification Number
001-09120	Public Service Enterprise Group Incorporated			New Jersey	22-2625848
	80 Park Plaza
	Newark,	New Jersey	07102
	973	430-7000

001-00973	Public Service Electric and Gas Company			New Jersey	22-1212800
	80 Park Plaza
	Newark,	New Jersey	07102
	973	430-7000

Securities registered pursuant to Section 12(b) of the Act:

Title of Each Class

Trading Symbol(s)

Name of Each Exchange
On Which Registered

Public Service Enterprise Group Incorporated

Common Stock without par value

PEG

New York Stock Exchange

Public Service Electric and Gas Company

8.00% First and Refunding Mortgage Bonds, due 2037

PEG37D

New York Stock Exchange

5.00% First and Refunding Mortgage Bonds, due 2037

PEG37J

New York Stock Exchange


Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark whether each registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

Public Service Enterprise Group Incorporated

☒

Yes

☐

Public Service Electric and Gas Company

☒

Yes

☐

Indicate by check mark if each of the registrants is not required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934. ☐ Yes ☒ No

Indicate by check mark whether each of the registrants (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports) and (2) has been subject to such filing requirements for the past 90 days. ☒ Yes ☐ No

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Indicate by check mark whether the registrants have submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrants were required to submit such files). ☒ Yes ☐ No

Indicate by check mark whether each registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Public Service Enterprise Group Incorporated

Large Accelerated Filer

☒

Accelerated Filer

☐

Non-accelerated Filer

☐

Smaller reportingcompany

☐

Emerging growth company

☐

Public Service Electric and Gas Company

Large Accelerated Filer

☐

Accelerated Filer

☐

Non-accelerated Filer

☒

Smaller reportingcompany

☐

Emerging growth company

☐

If any of the registrants is an emerging growth company, indicate by check mark if such registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether each of the registrants has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 726(b)) by the registered public accounting firm that prepared and issued its audit report.


Public Service Enterprise Group Incorporated						☒

Public Service Electric and Gas Company						☐

If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrants included in the filing reflect the correction of an error to previously issued financial statements. ☐

Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrants’ executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐

Indicate by check mark whether any of the registrants is a shell company (as defined in Rule 12b-2 of the Exchange Act).

☐ Yes ☒ No

The aggregate market value of the Common Stock of Public Service Enterprise Group Incorporated held by non-affiliates as of June 30, 2023 was $31,072,400,281 based upon the New York Stock Exchange Composite Transaction closing price.

The number of shares outstanding of Public Service Enterprise Group Incorporated’s sole class of Common Stock as of February 16, 2024 was 498,586,596.

As of February 16, 2024, Public Service Electric and Gas Company had issued and outstanding 132,450,344 shares of Common Stock, without nominal or par value, all of which were held, beneficially and of record, by Public Service Enterprise Group Incorporated.

Public Service Electric and Gas Company is a wholly owned subsidiary of Public Service Enterprise Group Incorporated and meets the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K. Public Service Electric and Gas Company is filing its Annual Report on Form 10-K with the reduced disclosure format authorized by General Instruction I.

DOCUMENTS INCORPORATED BY REFERENCE


Part of Form 10-K of Public Service Enterprise Group Incorporated						Documents Incorporated by Reference
III						Portions of the definitive Proxy Statement for the 2024 Annual Meeting of Stockholders of Public Service Enterprise Group Incorporated, which definitive Proxy Statement is expected to be filed with the Securities and Exchange Commission on or about March 7, 2024, as specified herein.

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TABLE OF CONTENTS


		Page
FORWARD-LOOKING STATEMENTS		iii
FILING FORMAT		1
WHERE TO FIND MORE INFORMATION		1
PART I
Item 1.	Business	1
	Operations and Strategy	2
	Competitive Environment	7
	Human Capital Management	8
	Regulatory Issues	9
	Environmental Matters	14
	Information About Our Executive Officers (PSEG)	16
Item 1A.	Risk Factors	17
Item 1B.	Unresolved Staff Comments	30
Item 1C.	Cybersecurity	30
Item 2.	Properties	33
Item 3.	Legal Proceedings	33
Item 4.	Mine Safety Disclosures	34
PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	34
Item 6.	[Reserved]	35
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	35
	Executive Overview of 2023 and Future Outlook	36
	Results of Operations	41
	Liquidity and Capital Resources	45
	Capital Requirements	49
	Critical Accounting Estimates	50
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	54
Item 8.	Financial Statements and Supplementary Data	55
	Report of Independent Registered Public Accounting Firm (PCAOB ID No. 34)	56
	Consolidated Financial Statements	60
	Notes to Consolidated Financial Statements
	Note 1. Organization, Basis of Presentation and Summary of Significant Accounting Policies	72
	Note 2. Revenues	77
	Note 3. Asset Dispositions and Impairments	82
	Note 4. Variable Interest Entity (VIE)	82
	Note 5. Property, Plant and Equipment and Jointly-Owned Facilities	83
	Note 6. Regulatory Assets and Liabilities	84
	Note 7. Leases	89
	Note 8. Long-Term Investments	93
	Note 9. Financing Receivables	93
	Note 10. Trust Investments	95
	Note 11. Asset Retirement Obligations (AROs)	100
	Note 12. Pension, Other Postretirement Benefits (OPEB) and Savings Plans	102
	Note 13. Commitments and Contingent Liabilities	111

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	TABLE OF CONTENTS (continued)
	Note 14. Debt and Credit Facilities	117
	Note 15. Schedule of Consolidated Capital Stock	121
	Note 16. Financial Risk Management Activities	121
	Note 17. Fair Value Measurements	126
	Note 18. Stock Based Compensation	129
	Note 19. Net Other Income (Deductions)	132
	Note 20. Income Taxes	133
	Note 21. Accumulated Other Comprehensive Income (Loss), Net of Tax	140
	Note 22. Earnings Per Share (EPS) and Dividends	142
	Note 23. Financial Information by Business Segment	142
	Note 24. Related-Party Transactions	145
Item 9.	Changes In and Disagreements With Accountants on Accounting and Financial Disclosure	146
Item 9A.	Controls and Procedures	146
Item 9B.	Other Information	146
Item 9C.	Disclosure Regarding Foreign Jurisdictions that Prevent Inspections	146
PART III
Item 10.	Directors, Executive Officers and Corporate Governance	150
Item 11.	Executive Compensation	151
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	151
Item 13.	Certain Relationships and Related Transactions, and Director Independence	151
Item 14.	Principal Accountant Fees and Services	151
PART IV
Item 15.	Exhibits, Financial Statement Schedules	152
	Schedule II - Valuation and Qualifying Accounts	157
	Signatures	158

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FORWARD-LOOKING STATEMENTS

Certain of the matters discussed in this report about our and our subsidiaries’ future performance, including, without limitation, future revenues, earnings, strategies, prospects, consequences and all other statements that are not purely historical constitute “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. Such forward-looking statements are subject to risks and uncertainties, which could cause actual results to differ materially from those anticipated. Such statements are based on management’s beliefs as well as assumptions made by and information currently available to management. When used herein, the words “anticipate,” “intend,” “estimate,” “believe,” “expect,” “plan,” “should,” “hypothetical,” “potential,” “forecast,” “project,” variations of such words and similar expressions are intended to identify forward-looking statements. Factors that may cause actual results to differ are often presented with the forward-looking statements themselves. Other factors that could cause actual results to differ materially from those contemplated in any forward-looking statements made by us herein are discussed in Item 1A. Risk Factors, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A), Item 8. Financial Statements and Supplementary Data—Note 13. Commitments and Contingent Liabilities, and other filings we make with the United States Securities and Exchange Commission (SEC), including our subsequent reports on Form 10-Q and Form 8-K. These factors include, but are not limited to:

•any inability to successfully develop, obtain regulatory approval for, or construct transmission and distribution, and our nuclear generation projects;

•the physical, financial and transition risks related to climate change, including risks relating to potentially increased legislative and regulatory burdens, changing customer preferences and lawsuits;

•any equipment failures, accidents, critical operating technology or business system failures, natural disasters, severe weather events, acts of war, terrorism or other acts of violence, sabotage, physical attacks or security breaches, cyberattacks or other incidents that may impact our ability to provide safe and reliable service to our customers;

•any inability to recover the carrying amount of our long-lived assets;

•disruptions or cost increases in our supply chain, including labor shortages;

•any inability to maintain sufficient liquidity or access sufficient capital on commercially reasonable terms;

•the impact of cybersecurity attacks or intrusions or other disruptions to our information technology, operational or other systems;

•a material shift away from natural gas toward increased electrification and a reduction in the use of natural gas;

•failure to attract and retain a qualified workforce;

•increases in the costs of equipment, materials, fuel, services and labor;

•the impact of our covenants in our debt instruments and credit agreements on our business;

•adverse performance of our defined benefit plan trust funds and Nuclear Decommissioning Trust Fund and increases in funding requirements and pension costs;

•any inability to extend certain significant contracts on terms acceptable to us;

•development, adoption and use of Artificial Intelligence by us and our third-party vendors;

•fluctuations in, or third-party default risk in wholesale power and natural gas markets, including the potential impacts on the economic viability of our generation units;

•our ability to obtain adequate nuclear fuel supply;

•changes in technology related to energy generation, distribution and consumption and changes in customer usage patterns;

•third-party credit risk relating to our sale of nuclear generation output and purchase of nuclear fuel;

•any inability to meet our commitments under forward sale obligations and Regional Transmission Organization rules;

•the impact of changes in state and federal legislation and regulations on our business, including PSE&G’s ability to recover costs and earn returns on authorized investments;

iii

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•PSE&G’s proposed investment projects or programs may not be fully approved by regulators and its capital investment may be lower than planned;

•our ability to receive sufficient financial support for our New Jersey nuclear plants from the markets, production tax credit and/or zero emission certificates program;

•adverse changes in and non-compliance with energy industry laws, policies, regulations and standards, including market structures and transmission planning and transmission returns;

•risks associated with our ownership and operation of nuclear facilities, including increased nuclear fuel storage costs, regulatory risks, such as compliance with the Atomic Energy Act and trade control, environmental and other regulations, as well as operational, financial, environmental and health and safety risks;

•changes in federal and state environmental laws and regulations and enforcement;

•delays in receipt of, or an inability to receive, necessary licenses and permits and siting approvals; and

•changes in tax laws and regulations.

All of the forward-looking statements made in this report are qualified by these cautionary statements and we cannot assure you that the results or developments anticipated by management will be realized or even if realized, will have the expected consequences to, or effects on, us or our business, prospects, financial condition, results of operations or cash flows. Readers are cautioned not to place undue reliance on these forward-looking statements in making any investment decision. Forward-looking statements made in this report apply only as of the date of this report. While we may elect to update forward-looking statements from time to time, we specifically disclaim any obligation to do so, even in light of new information or future events, unless otherwise required by applicable securities laws.

The forward-looking statements contained in this report are intended to qualify for the safe harbor provisions of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended.

From time to time, PSEG and PSE&G release important information via postings on their corporate Investor Relations website at https://investor.pseg.com. Investors and other interested parties are encouraged to visit the Investor Relations website to review new postings. You can sign up for automatic email alerts regarding new postings at the bottom of the webpage at https://investor.pseg.com or by navigating to the Email Alerts webpage at https://investor.pseg.com/resources/email-alerts/default.aspx. The information on https://investor.pseg.com and https://investor.pseg.com/resources/email-alerts/default.aspx is not incorporated herein and is not part of this Form 10-K.

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FILING FORMAT

This combined Annual Report on Form 10-K is separately filed by Public Service Enterprise Group Incorporated (PSEG) and Public Service Electric and Gas Company (PSE&G). Information relating to any individual company is filed by such company on its own behalf. PSE&G is only responsible for information about itself and its subsidiaries.

Discussions throughout the document refer to PSEG and its direct operating subsidiaries. Depending on the context of each section, references to “we,” “us,” and “our” relate to PSEG or to the specific company or companies being discussed.

WHERE TO FIND MORE INFORMATION

We file annual, quarterly and current reports, proxy statements and other information with the SEC. You may obtain our filed documents from commercial document retrieval services, the SEC’s internet website at www.sec.gov or our website at https://investor.pseg.com. Information on our website should not be deemed incorporated into or as a part of this report. Our Common Stock is listed on the New York Stock Exchange under the trading symbol PEG. You can obtain information about us at the offices of the New York Stock Exchange, Inc., 11 Wall Street, New York, New York 10005.

PART I

ITEM 1. BUSINESS

We were incorporated under the laws of the State of New Jersey in 1985 and our principal executive offices are located at 80 Park Plaza, Newark, New Jersey 07102. We principally conduct our business through two direct wholly owned subsidiaries, PSE&G and PSEG Power LLC (PSEG Power), each of which also has its principal executive offices at 80 Park Plaza, Newark, New Jersey 07102.

We are a public utility holding company consisting primarily of a regulated electric and gas utility and a nuclear generation business. Over the past several years, our investments resulted in a higher percentage of earnings contribution by PSE&G. The sale of the fossil generating portfolio in 2022 further simplified our business mix, resulting in an even higher percentage of earnings contribution by PSE&G going forward and provides more financial flexibility.

Our business approach focuses on operational excellence, financial strength and disciplined investment. As a holding company, our profitability depends on our subsidiaries’ operating results. Below are descriptions of our two principal direct operating subsidiaries.

•PSE&G—A New Jersey corporation, incorporated in 1924, which is a franchised public utility in New Jersey. It is also the provider of last resort for gas and electric commodity service for end users in its service territory. PSE&G earns revenues from its regulated rate tariffs under which it provides electric transmission and electric and natural gas distribution to residential, commercial and industrial (C&I) customers in its service territory. It also offers appliance services and repairs to customers throughout its service territory and invests in regulated solar generation projects and regulated energy efficiency (EE) and related programs in New Jersey.

•PSEG Power—A Delaware limited liability company formed in 1999 as a result of the deregulation and restructuring of the electric power industry in New Jersey. PSEG Power earns revenues from its nuclear generation and marketing of power and natural gas to hedge business risks and the value of its portfolio of nuclear power plants, other contractual arrangements and gas storage facilities.

In February 2022, we completed the sale of our 6,750 megawatt (MW) fossil generation portfolio which represented an important milestone in our strategy. See Item 8. Note 3. Asset Dispositions and Impairments for additional information.

Our other direct wholly owned subsidiaries are: 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 agreement; PSEG Energy Holdings L.L.C. (Energy Holdings), which primarily holds our legacy lease investments and competitively bid, FERC regulated transmission; and PSEG Services Corporation (Services), which provides us and our operating subsidiaries with certain management, administrative and general services at cost.

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OPERATIONS AND STRATEGY

PSE&G

Our regulated T&D public utility, PSE&G, distributes electric energy and natural gas to customers within a designated service territory running diagonally across New Jersey where approximately 6.8 million people, or about 74% of New Jersey’s population resides.

Products and Services

Our utility operations primarily earn margins through:

•Transmission—the movement of electricity at high voltage from generating plants to substations and transformers, where it is then reduced to a lower voltage for distribution to homes, businesses and industrial customers. Our revenues for these services are based upon tariffs approved by the Federal Energy Regulatory Commission (FERC).

•Distribution—the delivery of electricity and gas to the retail customer’s home, business or industrial facility. Our revenues for these services are based upon tariffs approved by the New Jersey Board of Public Utilities (BPU).

The commodity portion of our utility business’ electric and gas sales is managed by basic generation service (BGS) and basic gas supply service (BGSS) suppliers. Pricing for those services is set by the BPU as a pass-through, resulting in no margin for our utility operations.

In addition, we continue to invest in and pursue opportunities in regulated clean energy, including EE, electric vehicle (EV) make-ready charging infrastructure, solar, energy storage and other potential investments.

We also earn margins through competitive services, such as appliance repair, in our service territory.

How PSE&G Operates

We are a transmission owner in PJM Interconnection, L.L.C. (PJM) which is an Independent System Operator (ISO) and Regional Transmission Organization (RTO) that operates the electric transmission system in the Mid-Atlantic Region, including

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New Jersey and the surrounding states. We provide distribution service to 2.4 million electric customers and 1.9 million gas customers in a service area that covers approximately 2,600 square miles running diagonally across New Jersey. We serve the most densely populated, commercialized and industrialized territory in New Jersey, including its six largest cities and approximately 300 suburban and rural communities.

Transmission

We use formula rates for our transmission cost of service and investments. Formula rates provide a method of rate recovery where the transmission owner annually determines its revenue requirements through a fixed formula that provides for a recovery of our operating costs and a return of and on our capital investments in the system, net of accumulated depreciation and deferred tax liabilities (also known as rate base) using an approved return on equity (ROE) in developing the weighted average cost of capital. Under this formula, rates are put into effect in January of each year based upon our internal forecast of annual expenses and capital expenditures. Rates are subsequently trued up to reflect actual annual expenses and capital expenditures. Our transmission revenues are not impacted by sales volumes. Our current approved transmission rates provide for a base ROE of 9.90% and a 50 basis point adder for our membership in PJM as an RTO. See Item 7. MD&A—Executive Overview of 2023 and Future Outlook.

Distribution

PSE&G distributes electricity and natural gas to end users in our respective franchised service territories. Our distribution rates are subject to periodic rate cases approved by the BPU. The BPU has also approved a series of PSE&G infrastructure, EE, EV and renewable energy investment programs with cost recovery through various clause mechanisms. Our current approved

distribution base rates provide for an ROE of 9.6%. In December 2023, we filed a distribution base rate case as required by the BPU. For a discussion of our recent distribution base rate case filing, see Item 7. MD&A—Executive Overview of 2023 and Future Outlook. For a discussion of proposed and approved programs, see Investment Clause Programs as follows and Item 7. MD&A—Executive Overview of 2023 and Future Outlook. Our load requirements are split among residential, C&I customers, as described in the following table for 2023:



	% of 2023 Sales
Customer Type	Electric	Gas
Commercial	58%	38%
Residential	33%	58%
Industrial	9%	4%
Total	100%	100%

Our customer base has modestly increased since 2019, with electric and gas loads changing as illustrated in the following table:



Electric and Gas Distribution Statistics

	Number of Customers as of December 31, 2023		Historical Annual Customer Growth 2019-2023		Electric Sales and Firm Gas Sales as of December 31, 2023 (A)		Historical Annual Load Decline 2019-2023
Electric	2.4	Million	0.9	%	39,085	Gigawatt hours	(1.4)%
Gas	1.9	Million	0.6	%	2,282	Million Therms	(2.8)%

(A)Excludes sales from Gas rate classes that do not impact margin, specifically Contract, Non-Firm Transportation, Cogeneration Interruptible and Interruptible Services.

Effective June 1 and October 1, 2021 for electric and gas, respectively, as part of the BPU’s approval of the Clean Energy Future-Energy Efficiency (CEF-EE) filing, we implemented the Conservation Incentive Program (CIP) that trues up PSE&G’s margin to a baseline per customer from our 2018 distribution base rate case for the majority of our customers. As a result, electric gas sales volumes and demands are no longer a driver of our margin and over 90% of our Electric and Gas Distribution margin will only vary based upon the number of customers. While there has been a recent decrease in load due to a decline in larger industrial customers, greater EE and other factors, PJM’s most recent forecast indicates an increase in load over the next several years due to the increasing adoption of EVs, the expansion of data centers and other large users in our area, ongoing growth in the number of customers, other sources of electrification and other factors, which will collectively drive the need for increased system investment in the future.

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Investment Clause Programs

The following table lists our major approved investment clause programs that are in progress:

Program

Investment

Approval Date

Term of Investment

Year Started

Gas System Modernization Program II (GSMP II) Extension

$902 million

2023

2 years

(A)

2024

Energy Strong II Program

$842 million

2019

4 years

(B)

2019

CEF-EE

$1 billion

2020

5 years

(C)

2020

CEF-EE Extension

$280 million

2023

9 months

2023

CEF-Energy Cloud (EC)

$707 million

2021

4 years

2021

CEF-EV

$166 million

2021

~6 years

2021

Infrastructure Advancement Program (IAP)

$511 million

2022

4 years

2022

(A)The program has a small amount of trailing costs expected to be spent in year 3.

(B)The program has a small amount of trailing costs expected to be spent in year 5.

(C)Rolling three-year program with over 80% of spending within 5 years, with limited spending thereafter.

GSMP II Extension—designed to replace at least 400 miles of cast iron and unprotected steel mains and services in our gas system.

Energy Strong II Program—structured to harden, modernize and improve the resiliency of our electric and gas distribution systems.

To date, we launched three of the four components of our CEF:

•EE—designed to achieve EE targets required under New Jersey’s Clean Energy Act through a suite of ten programs for residential, C&I programs, including low-income, multi-family, small business and local government.

•EC—driven by the implementation of “smart meters,” and new software and product solutions to improve our processes and better manage the electric grid.

•EV—primarily relating to preparatory work to deliver infrastructure to the charging point for three programs: residential smart charging; Level-2 mixed use charging; and direct current (dc) fast charging.

Our CEF-Energy Storage (ES) program, which was filed with the BPU in October 2018, is being held in abeyance. Our proposed ES program is for a $109 million investment that encompasses solar smoothing, whereby a battery energy solar system is used to neutralize fluctuations in solar output to facilitate its entry into the grid, distribution investment deferral, outage management, microgrids and peak reduction for municipal facilities.

IAP—designed to improve the reliability of the “last mile” of our electric distribution system and address aging substations and gas metering and regulation stations.

See Item 7. MD&A—Executive Overview of 2023 and Future Outlook for additional information.

Solar Generation

We have also undertaken solar initiatives at PSE&G, which primarily invest in utility-owned solar photovoltaic (PV) grid-connected solar systems installed on PSE&G property and third-party sites with our economics driven by our net investment in solar, with a contemporaneous return on that rate base.

Supply

We make no margin on the default supply of electricity and gas since the actual costs are passed through to our customers.

All electric and gas customers in New Jersey have the ability to choose their electric energy and/or gas supplier. Pursuant to BPU requirements, we serve as the supplier of last resort for two types of electric and gas customers within our service territory that are not served by another supplier. The first type provides default supply service for smaller C&I customers and residential customers at seasonally-adjusted fixed prices for a three-year term (BGS-Residential Small Commercial Pricing (RSCP)). These rates change annually on June 1 and are based on the average price obtained at auctions in the current year and two prior years. The second type provides default supply for larger customers, with energy priced at hourly PJM real-time market prices for a contract term of 12 months (BGS-Commercial Industrial Energy Pricing).

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We procure the supply to meet our BGS obligations through auctions authorized by the BPU for New Jersey’s total BGS requirement. These auctions take place annually in February. Once validated by the BPU, electricity prices for BGS service are set. Approximately one-third of PSE&G’s total BGS-RSCP eligible load is auctioned each year for a three-year term. For information on current prices, see Item 8. Note 13. Commitments and Contingent Liabilities.

PSE&G procures the supply requirements of its default service BGSS gas customers through a full-requirements contract with PSEG Power. The BPU has approved a mechanism designed to recover all gas commodity costs related to BGSS for residential customers. BGSS filings are made annually by June 1 of each year, with a targeted effective date of provisional rates by October 1. PSE&G’s revenues are matched with its costs using deferral accounting, with the goal of achieving a zero cumulative balance by September 30 of each year. In addition, we have the ability to put in place two self-implementing BGSS increases on December 1 and February 1 of up to 5% and also may reduce the BGSS rate at any time and/or provide bill credits. Any difference between rates charged under the BGSS contract and rates charged to our residential customers is deferred and collected or refunded through adjustments in future rates. C&I customers that do not select third-party suppliers are also supplied under the BGSS arrangement. These customers are charged a market-based price largely determined by prices for commodity futures contracts.

PSEG Power & Other

PSEG Power & Other is predominantly comprised of its nuclear generation assets, its natural gas supply operations, the Operating Services Agreement (OSA) of PSEG LI with LIPA, and other legacy investments. PSEG Power is a public utility within the meaning of the Federal Power Act (FPA) and the payments it receives and how it operates are subject to FERC regulation.

PSEG Power

Products and Services

As a nuclear generation owner and operator, our revenue has been derived primarily from energy, capacity and ancillary services sold to PJM in the spot markets. These products and services may also be transacted through exchange markets or bilaterally.

In August 2022, the Inflation Reduction Act (IRA) was signed into law expanding incentives that promote carbon-free generation. The enacted legislation established the production tax credit (PTC) for electricity generation using nuclear energy, which begins January 1, 2024 and is available through 2032. PSEG Power’s Salem 1, Salem 2, Hope Creek, Peach Bottom 2 and Peach Bottom 3 nuclear plants are expected to benefit from the PTC. The expected PTC rate is up to $15 per megawatt hour (MWh) subject to adjustment based upon a facility’s gross receipts and meeting prevailing wage rules. The PTC rate and the gross receipts threshold are subject to annual inflation adjustments. Until additional guidance is issued by the U.S. Treasury, we are unable to fully determine the impacts of the PTC.

PSEG Power also sells wholesale natural gas, primarily through a full-requirements BGSS contract with PSE&G to meet the needs of PSE&G’s default service customers. In 2022, the BPU approved an extension of the long-term BGSS contract to March 31, 2027, and thereafter the contract remains in effect unless terminated by either party with a two-year notice.

PSEG Power supplies PSE&G’s peak daily gas requirements through its balanced portfolio of firm gas transportation capacity, storage contracts, contract peaking supply, and liquefied natural gas and propane. Based upon the availability of natural gas beyond PSE&G’s actual daily needs, PSEG Power sells gas to other customers and shares these proceeds with PSE&G’s customers.

How PSEG Power’s Nuclear Generation Operates

As of December 31, 2023, PSEG Power had 3,761 MW of nuclear generation capacity. All of our nuclear generation capacity is located in New Jersey and Pennsylvania.

Generation Dispatch

Our nuclear generation is considered to be base load. Base load units run the most and typically are called to operate whenever they are available. Variable operating costs are low due to the combination of highly efficient operations and the use of relatively lower-cost fuels. Performance is generally measured by the unit’s “capacity factor,” or the ratio of the actual output to the theoretical maximum output.

In PJM, owners of power plants specify prices at which they are prepared to generate and sell energy based on the marginal cost of generating energy from each individual unit. Typically, the bid price of the last unit dispatched by PJM establishes the energy market-clearing price.

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This method of determining supply and pricing creates a situation where natural gas prices often have a major influence on the price that generators will receive for their output, especially in periods of relatively strong or weak demand. Therefore, changes in the price of natural gas will often translate into changes in the wholesale price of electricity and will continue to have a strong influence on the price of electricity in the markets in which we operate.

Market wholesale prices may vary by location resulting from congestion or other factors and do not necessarily reflect our contract prices. Forward prices are volatile and there can be no assurance that current forward prices will remain in effect or that we will be able to contract output at these forward prices. The PTC is expected to mitigate our exposure to this volatility and provide support for the nuclear units.

Nuclear Fuel Supply

We have long-term contracts for nuclear fuel. These contracts provide for:

•purchase of uranium (concentrates and uranium hexafluoride),

•conversion of uranium concentrates to uranium hexafluoride,

•enrichment of uranium hexafluoride, and

•fabrication of nuclear fuel assemblies.

We expect to be able to meet the nuclear fuel supply demands of our operations. However, the ability to maintain an adequate fuel supply could be affected by several factors not within our control, including changes in prices and demand, curtailments by suppliers, severe weather, environmental regulations, war and hostilities, and other factors. For additional information and a discussion of risks, see Item 1A. Risk Factors, Item 7. MD&A—Executive Overview of 2023 and Future Outlook and Item 8. Note 13. Commitments and Contingent Liabilities.

Markets and Market Pricing

All of PSEG Power’s nuclear generation assets are located within the PJM RTO.

Our nuclear generating units’ performance, together with the PTC, have a considerable effect on our profitability. The PTC is designed to increase with inflation, and therefore, future inflation levels will impact the financial support of the nuclear units. In addition, market revenues in excess of the PTC threshold would provide incremental benefit.

PSEG Power’s Salem 1, Salem 2 and Hope Creek nuclear plants have also 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, which is equivalent to approximately $10/MWh. The number of ZECs purchased by each EDC from a selected nuclear power plant for an energy year is expected to be reduced by the number of ZECs equal in value to the dollar amount of PTCs received by the same plants.

In addition to energy sales, we earn revenue from capacity payments for our generating assets. These payments are compensation for committing our generating units to PJM for dispatch at its discretion. Capacity payments reflect the value to PJM of assurance that there will be sufficient generating capacity available at all times to meet system reliability and energy requirements.

In PJM the market design for capacity payments provides for a structured, forward-looking, capacity pricing mechanism through the Reliability Pricing Model (RPM). For additional information regarding FERC actions related to the capacity market construct, see Regulatory Issues—Federal Regulation.

The prices to be received by generating units in PJM for capacity have been set through RPM base residual and incremental auctions and depend upon the zone in which the generating unit is located. The average capacity prices that PSEG expects to receive from the base residual and incremental auctions which have been completed are disclosed in Item 8. Note 2. Revenues.

In addition, the PJM capacity market imposes rigorous performance obligations and non-performance penalties on resources during times of system stress. These rules provide an opportunity for bonus payments or require the payment of penalties depending on whether a unit is available during a performance interval.

Hedging Strategy

The PTC is intended to provide sufficient and stable support for nuclear units and is effective January 1, 2024. To mitigate volatility in our results, we seek to contract in advance to hedge the price exposure for a significant portion of our anticipated electric output, capacity and fuel needs. We historically have sold a portion of our anticipated generation over a multi-year forward horizon, normally over a period of two to three years. As of the end of 2023, we have hedged approximately 90% to 95% of its expected generation output for 2024. Beginning in 2024, our hedging strategy will incorporate an estimated range of risk reduction impacts from the PTCs on our nuclear generation portfolio. This is expected to result in changes to our current approach given PTC guidance uncertainty, and potential incremental changes upon final U.S. Treasury guidance.

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Generally, we seek to hedge our output through sales at PJM West or other nodes corresponding to our generation portfolio. Sales in PJM generally reflect block energy sales at the liquid PJM Western Hub or other basis locations when available and other transactions that seek to secure price certainty for our energy output. Although we enter into these hedges to provide price certainty for a large portion of our anticipated generation, there is variability in both our actual output as well as in the effectiveness of our hedges. Our hedging practices help to manage some of the volatility of the nuclear generation business. While this limits our exposure to decreasing prices, our ability to realize benefits from rising market prices is also limited.

The expected PTC rate is up to $15/MWh subject to adjustment based upon a facility’s gross receipts. The U.S. Treasury is expected to clarify the definition of gross receipts as the eligibility period begins January 1, 2024. We are continuing to analyze the impact of the IRA on our nuclear units, including additional future guidance from the U.S. Treasury, potential impacts on hedging strategies and overall financial support.

Our fuel strategy is to maintain certain levels of uranium in inventory and to make periodic purchases to support such levels. Our nuclear fuel commitments cover approximately 100% of our estimated uranium, enrichment and fabrication requirements through 2026 and a significant portion through 2027.

LIPA Operations Services Agreement

In accordance with a 12-year OSA entered into by PSEG LI and LIPA, PSEG LI commenced operating LIPA’s electric T&D system in Long Island, New York on January 1, 2014. The OSA contract term continues through 2025, but can be extended subject to a mutual agreement of the parties. Under the OSA, PSEG LI acts as LIPA’s agent in performing many of its obligations and in return (a) is prefunded for pass-through operating expenditures, (b) receives a fixed management fee and (c) is eligible to receive an incentive fee contingent on meeting established performance metrics. Further, since January 2015, PSEG Power provides fuel procurement and power management services to LIPA under separate agreements that expire at the end of 2025. It is uncertain whether the OSA and the separate agreements will be renewed on terms acceptable to us or at all.

Energy Holdings

Energy Holdings maintains our portfolio of legacy lease investments. See Item 8. Note 8. Long-Term Investments and Note 9. Financing Receivables for additional information.

Energy Holdings also owns 50% of Garden State Offshore Energy LLC (GSOE) which holds rights to an offshore wind lease area just south of New Jersey. We are evaluating our options for the potential sale of our interest in GSOE.

In December 2023, PJM awarded a subsidiary of Energy Holdings an approximately $424 million project to construct a 500 kV transmission line in Maryland. PSEG’s project was part of a larger set of projects designed to address reliability issues driven by load growth and retirement of fossil generation. Our project is expected to be placed in service in 2027.

COMPETITIVE ENVIRONMENT

PSE&G

Our T&D business is not affected when customers choose alternate electric or gas suppliers since we earn our return on our net investment in rate base to provide T&D service, not by supplying the commodity. Based on our transmission formula rate and the CIP program for electric and gas distribution, we are also minimally impacted by changes in customers’ usage. Our growth is driven by (i) our investment program to deliver energy more reliably by modernizing our electric transmission and electric and gas distribution system and (ii) investing in programs that help deliver cleaner energy, including our EE programs to help customers use less energy and investment programs to build EV infrastructure and solar generation. There may also be opportunities to expand into related clean energy areas, such as renewable natural gas, hydrogen, energy storage, additional solar and renewables, and broader EE investments, though utility participation in these areas is subject to regulatory approval and market design, which continues to evolve. That growth can be affected by customer cost pressures which could result from higher commodity costs, higher supply costs to support subsidized renewable generation, higher operating costs, higher tax rates, macro-economic conditions including inflation, and other factors. While there is not a substantial amount of net metered generation in our territory, a growing amount, and/or other changes in customer usage behavior could lead to a smaller base of customer usage to recover our costs, resulting in higher rates overall. Conversely, an increase in EV adoption and other factors could lead to an increase in system usage, require incremental investments to meet higher peak demands and result in a larger customer usage base. There is also an expected shift toward greater electrification and less gas usage in the coming decades. While current costs and relative emission savings would limit any substantial change in the near term, technological advances for heat pumps, actions by certain jurisdictions in our service territory and other factors could accelerate these potential changes, which could result in a slowing in the growth of our gas distribution and an increase in the growth of our electric T&D business. Our CIP reduces the impact on our distribution revenues from changes in sales volumes and demand for most customers. The CIP, which is calculated annually, provides for a true-up of our current period revenue as compared to revenue

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thresholds established in our most recent distribution base rate proceeding. Recovery under the CIP is subject to certain limitations, including an actual versus allowed ROE test and ceilings on customer rate increases.

Changes previously ordered by FERC and implemented by PJM and other ISOs to eliminate contractual provisions that previously provided us a “right of first refusal” to construct new transmission projects in our service territory, could result in third-party construction of transmission lines in our area in the future and also allow us to seek opportunities to build in other service territories. While there has been minimal impact so far, these rules continue to evolve so both the extent of the risk within our service territory and the opportunities for our transmission business elsewhere remain difficult to assess.

PSEG Power

Various market participants compete with us and one another in transacting in the wholesale energy markets and entering into bilateral contracts. Our competitors include but are not limited to merchant generators, utility generators, energy marketers, retailers, private equity firms, and other financial entities.

New additions of lower-cost or more efficient generation capacity, as well as subsidized generation capacity, or technological advances could impact forward market prices in the future.

PJM has a capacity market that has been approved by FERC. FERC regulates this market and continues to examine whether this market design is working optimally. For information regarding recent actions by FERC relating to capacity market design, see the discussion in Regulatory Issues—Federal Regulation.

Environmental issues could also impact our competitiveness, including requirements regarding capital investments at our nuclear stations, such as cooling towers, could lead to a material adverse effect, while other actions to further regulate carbon dioxide emissions could better position our nuclear plants.

HUMAN CAPITAL MANAGEMENT

Our Core Commitments – safety, integrity, continuous improvement, customer service and diversity, equity and inclusion (DEI) – are at the center of our workplace culture. They guide us in important aspects of our Human Capital Management strategy, including recruitment, employee development, retention, performance, safety, and collaboration. We rely on our inclusive culture to support our many stakeholders including employees, customers, and the many diverse communities we serve. We believe in treating people with dignity and respect, protecting each of our fundamental human rights, and we strive to maintain the high standards of ethical conduct on which our business and reputation have been built.

Our human capital management strategy is integrated with our overall business strategy. Relying on our core commitments and strong culture of inclusion, our focus is to attract, develop, and retain a high performing diverse workforce - one with the skill sets needed to succeed in a rapidly evolving environment.

Over 60% of our workforce is represented by six unions under various collective bargaining agreements that cover wages, benefits and other terms and conditions of employment. In 2023, we negotiated new agreements with all six of our unions in advance of contract expiration. These agreements contain four-year terms, expiring in 2027 and support strategic objectives and business goals.

The Organization and Compensation Committee of the PSEG Board of Directors is responsible for oversight of PSEG’s human capital management practices and is updated regularly on matters related to executive leadership succession and development, culture, and DEI. Safety metrics, such as Occupational Safety and Health Administration (OSHA) recordable incidence rate, OSHA days away from work rate, and serious injury incidence rate, are regularly monitored and reported to our Board.

The following charts present our total employee population indicating percentages of employees that are represented by a collective bargaining unit, are women, or are racially and/or ethnically diverse:

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Health, Safety and Well-Being

We value the health, safety, security and well-being of our employees, contractors and the communities that we serve. We demonstrate this by providing support to employees so that everyone is empowered and encouraged to question, stop and correct any unsafe act or condition. We take measures to provide employees and contractors with proper knowledge, training and protective equipment to maintain their personal health and safety and to mitigate workplace risks.

Culture, Diversity, Equity and Inclusion

We incorporate DEI throughout the employee life cycle and build on our Inclusion for All strategy. Since everyone is responsible for DEI and work-place culture, employees have many opportunities to influence the work environment, let their voices be heard and to step up and lead. Our efforts are led by the PSEG Office of DEI. It is supported by our Employee Business Resource Groups and the Local Inclusion Teams within our business units and field locations. The Office of DEI works to make sure our programs such as community outreach and volunteerism, mentorship, recognition and professional development, are relevant and accessible to all employees.

To determine if we are being responsive to the needs of our employees, we routinely assess the impact of our work by soliciting employee feedback through focus groups, listening sessions, pulse surveys and a biennial employee engagement survey.

Our initiatives to advance DEI include doing business with certified minority, women, veteran and service-disabled veteran-owned businesses as well as LGBTQ+-owned businesses and continuously improving our supplier diversity process which is integrated into our company culture.

Talent, Attraction and Workforce Development

Our talent acquisition strategy is focused on hiring a diverse, high-performing workforce to meet our business objectives, including the critical skilled trade roles needed to provide energy that is safer and delivered more reliably than ever. As part of these efforts, we work to attract employees who reflect broad dimensions of diversity, including race, gender, disability, generation, education, and other traits and characteristics that make each person who they are.

Our employees grow through a variety of training and development opportunities offered to individual contributors, front line supervisors, managers and leaders. Talent reviews and succession planning for senior and critical positions are key components of our workforce planning strategy. We continue to identify and develop internal talent to step into key roles, minimizing any potential disruptions to our operations. We invest in technical and operational training for our craft and field workers to support safe and reliable operations. We continue to focus on hiring ahead of attrition and upskilling our skilled trade roles to adapt to evolving technologies and digital advancements.

Total Rewards

We support the well-being of our employees through a comprehensive total rewards program. We provide compensation to our workforce and a benefit program that is designed to support mental and physical health and emotional and financial wellness. In 2023, we performed a total rewards study, which included a comprehensive evaluation of our performance management process, compensation structure and design as well as pay fairness review.

REGULATORY ISSUES

In the ordinary course of our business, we are subject to regulation by, and are party to various claims and regulatory proceedings with FERC, the BPU, the Commodity Futures Trading Commission (CFTC) and various state and federal environmental regulators, among others. For information regarding material matters, other than those discussed below, see Item 8. Note 13. Commitments and Contingent Liabilities. In addition, information regarding PSE&G’s specific filings pending before the BPU is discussed in Item 8. Note 6. Regulatory Assets and Liabilities.

Federal Regulation

FERC is an independent federal agency that regulates the transmission of electric energy and natural gas in interstate commerce and the sale of electric energy and natural gas at wholesale pursuant to the FPA and the Natural Gas Act. PSE&G and certain operating subsidiaries of PSEG Power are public utilities as defined by the FPA. FERC has extensive oversight over such public utilities. FERC approval is usually required when a public utility seeks to: sell or acquire an asset that is regulated by FERC (such as a transmission line or a generating station); collect costs from customers associated with a new transmission facility; charge a rate for wholesale sales under a contract or tariff; or engage in certain mergers and internal corporate reorganizations.

FERC also regulates RTOs/ISOs, such as PJM, and their regional transmission planning processes as well as their energy and capacity markets.

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Transmission Regulation

FERC has exclusive jurisdiction to establish the rates and terms and conditions of service for interstate transmission. We currently have FERC-approved formula rates in effect to recover the costs of our transmission facilities. Under this formula, rates are put into effect in January of each year based upon our internal forecast of annual expenses and capital expenditures. Rates are subsequently trued up to reflect actual annual expenses and capital expenditures.

Transmission Rate Proceedings and ROE—From time to time, various matters are pending before FERC relating to, among other things, transmission planning, reliability standards and transmission rates and returns, including incentives. Depending on their outcome, any of these matters could materially impact our results of operations and financial condition.

In a rulemaking proceeding issued in 2021, FERC proposed to eliminate the existing 50 basis point adder for RTO membership, which is currently available to PSE&G and other transmission owners in RTOs. Elimination of the RTO adder for RTO membership would reduce PSE&G’s annual Net Income and annual cash inflows by approximately $40 million.

Transmission Planning Proceedings—Through rulemaking proceedings, FERC continues to determine whether changes are needed to current transmission and interconnection planning rules to facilitate the integration of renewable resources onto the grid. FERC is also examining whether there is sufficient oversight over transmission costs to protect customers. Among other issues, FERC is considering whether transmission competitive solicitations are working as intended, whether interconnection queue rules for new generation should dramatically change and whether some type of transmission monitor construct to oversee costs should be imposed. On the interconnection front, in July 2023, FERC issued a Final Rule, which parties have challenged on rehearing, that will require RTOs to implement rules to speed up the processing of interconnection queue requests. This Rule may also result in penalties being imposed on generators, RTOs and transmission owners that fail to meet certain process deadlines.

Regulation of Wholesale Sales—Generation/Market Issues/Market Power

Under FERC regulations, public utilities that wish to sell power at market rates must receive FERC authorization (market-based rate (MBR) authority) to sell power in interstate commerce before making power sales. They can sell power at cost-based rates or apply to FERC for authority to make MBR sales. For a requesting company to receive MBR authority, FERC must first determine that the requesting company lacks market power in the relevant markets and/or that market power in the relevant markets is sufficiently mitigated. Certain PSEG companies are public utilities and currently have MBR authority. These companies, which include PSEG Energy Resources & Trading LLC, PSEG Nuclear LLC and PSE&G must file at FERC every three years to update their market power analyses. At the end of 2022, PSEG filed such a market power update at FERC, which remains pending.

Energy Clearing Prices

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, including those owned by PSEG, 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.

Capacity Market Issues

PJM operates a capacity market called the Reliability Pricing Model (RPM), the rules for which are approved by FERC. RPM incorporates a forward auction for installed capacity. Under the RPM, generators located in constrained areas within PJM are paid more for their capacity as an incentive to ensure adequate supply where generation capacity is most needed. The mechanics of the RPM in PJM continue to evolve and be refined in stakeholder proceedings and FERC proceedings in which we are active.

In October 2023, PJM submitted two related filings at FERC proposing reforms to its capacity market design, including (i) enhanced risk modeling to better account for winter risk; (ii) changes to supply-side market power mitigation rules; and (iii) more stringent capacity qualification and performance requirements. In January 2024, FERC issued an order approving PJM’s reforms relating to enhanced risk modeling and qualification and performance requirements. However, in February 2024, FERC issued an order rejecting PJM’s second package of reforms, including PJM’s proposed changes to its supply-side market power mitigation rules. At the same time, in this order FERC provided guidance to PJM should PJM choose to develop an alternate proposal in the future. Various parties may seek rehearing of FERC’s rejection order. In February 2024, PJM submitted a request asking FERC to delay the commencement of the base residual auction for the 2025/26 Delivery Year to mid-July 2024. This request is pending before FERC.

In late December 2022, PJM called its first ISO-wide Maximum Generation Emergency Action during Winter Storm Elliott, which triggered a Performance Assessment Interval (PAI) event. As a result of this event, PSEG both incurred penalties and received bonuses under PJM’s capacity performance rules, neither of which were material to PSEG’s financial results in 2022

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or 2023. Many generators filed complaints at PJM seeking to reduce or eliminate their obligations to pay non-performance penalties incurred during the event. Parties ultimately reached a settlement effectuating a penalty reduction that was not material to PSEG. In December 2023, FERC approved the settlement.

Compliance

Reliability Standards—Congress has required FERC to put in place, through the North American Electric Reliability Corporation (NERC), national and regional reliability standards to ensure the security and reliability of the U.S. electric transmission and generation system (grid) and to prevent major system blackouts. As a result, under NERC’s physical security standard, approved by FERC in 2015, utilities are required to identify critical substations as well as develop threat assessment plans to be reviewed by independent third parties. In our case, the third party is PJM. As part of these plans, utilities can decide or be required to build additional redundancy into their systems. As a result of physical attacks in 2022 to electric infrastructure, NERC is studying whether the physical security standard should be revised. Moreover, under NERC’s supply chain standard approved by FERC in 2018, PSEG has developed physical and cybersecurity controls for supply chain management associated with the procurement of industrial control system hardware, software, and services related to grid operations.

In February 2023, FERC approved additional reliability standards governing extreme cold weather preparedness and operations, which will begin going into effect in 2024. We continue to analyze these new standards. FERC and NERC continue to study potential revisions to reliability standards regarding extreme cold weather. Relatedly, in November 2023, FERC and NERC released a report regarding the operation of the Bulk Power System (BPS) during Winter Storm Elliott that struck in late 2022, causing power outages for millions and significantly straining the BPS in certain regions of the country, and proposed recommendations. These recommendations for extreme cold weather events include: (i) creation of additional reliability standards to strengthen generator operations; (ii) legislation or regulations to ensure the reliability of natural gas infrastructure; (iii) identification of high risk generating units and conducting cold weather verifications of these units; and (iv) improving short-term load forecasts for extreme cold weather events.

In June 2023, FERC issued a rule directing NERC to either change existing reliability standards or create a new standard that will require RTOs like PJM to plan for extreme weather events. In October 2023, pursuant to FERC’s rule, PSE&G, along with PJM and other RTOs, jointly submitted an informational report describing their policies and processes for conducting extreme weather vulnerability assessments.

Investor Ownership of Public Utilities—In December 2023, FERC proposed new rules that, if finalized, would mean that institutional investors in FERC-regulated public utilities or in holding companies with public utility affiliates will need to obtain approval from FERC before acquiring such an ownership interest that exceeds a defined monetary threshold. Under current rules, investors are able to rely upon blanket authorizations to make such investments and are not required to obtain FERC approval for specific stock acquisitions. FERC is concerned that there is insufficient oversight to protect consumers and is seeking public comment on the proposed rules. We cannot predict the outcome of this rulemaking proceeding.

CFTC

In accordance with the Dodd-Frank Wall Street Reform and Consumer Protection Act, the SEC and the CFTC continue to implement a regulatory framework for swaps and security-based swaps. The rules are intended to reduce risk, increase transparency and promote market integrity within the financial system by providing for the registration and comprehensive regulation of swap dealers and by imposing recordkeeping, data reporting, margin and clearing requirements with respect to swaps. We are currently subject to recordkeeping and data reporting requirements applicable to commercial end users. The CFTC finalized new rules establishing federal position limits for trading in certain commodities, such as natural gas. Entities such as PSEG began complying with the rules on January 1, 2022.

Nuclear

Nuclear Regulatory Commission (NRC)

Our operation of nuclear generating facilities is subject to comprehensive regulation by the NRC, a federal agency established to regulate nuclear activities to ensure the protection of public health and safety, as well as the environment. Such regulation involves testing, evaluation and modification of all aspects of plant operation in light of NRC safety, security, cybersecurity, and environmental requirements. Continuous demonstration to the NRC that plant operations meet requirements is necessary.

The NRC has the ultimate authority to determine whether any U.S. nuclear generating unit may operate. The NRC conducts ongoing reviews of nuclear industry operations experience and may issue or revise regulatory requirements. 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 the Salem, Hope Creek and Peach Bottom facilities, but such costs could be material.

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The current operating licenses of our nuclear facilities expire in the years shown in the following table:



			Unit						Year
			Salem Unit 1						2036
			Salem Unit 2						2040
			Hope Creek						2046
			Peach Bottom Unit 2 (A)						2033
			Peach Bottom Unit 3 (A)						2034

(A)Depreciation Expense and the Asset Retirement Obligation assume these units will operate through 2053 and 2054, respectively, given our expectation that previously approved operating license expiration dates will be restored by the NRC. See Item 8. Note 11. Asset Retirement Obligations (AROs) for additional information.

State Regulation

Our principal state regulator is the BPU, which oversees electric and natural gas distribution companies in New Jersey. We are also subject to various other states’ regulations due to our operations in those states.

Our New Jersey utility operations are subject to comprehensive regulation by the BPU including, among other matters, regulation of retail electric and gas distribution rates and service, the issuance and sale of certain types of securities and compliance matters.

In addition to base rates, we recover certain costs or earn on certain investments pursuant to mechanisms known as adjustment clauses. These clauses permit the flow-through of costs to, or the recovery of investments from, customers related to specific programs, outside the context of base rate proceedings. Recovery of these costs or investments is subject to BPU approval for which we make periodic filings. Delays in the pass-through of costs or recovery of investments under these mechanisms could result in significant changes in PSE&G’s cash flow. PSE&G’s participation in solar, EV and EE programs is also regulated by the BPU, as the terms and conditions of these programs are approved by the BPU. BPU regulation can also have a direct or indirect impact on our power generation business as it relates to energy supply agreements and energy policy in New Jersey.

New Jersey Energy Master Plan (EMP) and Future of Gas Stakeholder Proceeding—In January 2020, the State of New Jersey released its EMP. While the EMP does not have the force of law and does not impose any obligations on utilities, it outlines current expectations regarding the New Jersey’s role in the use, management, and development of energy. The EMP recognizes the goals of New Jersey’s Clean Energy Act of 2018 (the Clean Energy Act) to achieve, by 2026, annual reductions of electric and gas consumption of at least 2% and 0.75%, respectively, of the average of the prior three years of retail sales. The annual reductions were subsequently adjusted to 2.15% for electric and 1.10% for gas by 2027 in the BPU’s EE framework approved in June 2020. The EMP outlines several strategies, including statewide EE programs; expansion of renewable generation (solar and offshore wind), energy storage and other carbon-free technologies; preservation of existing nuclear generation; electrification of the transportation sector; and reduced reliance on natural gas.

In February 2023, the governor of New Jersey issued three Executive Orders (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 commenced 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 New Jersey’s goals, among other things. The BPU Board is seeking to retain a consultant to assist with this proceeding, and is expected to convene additional working groups and/or stakeholder sessions in 2024. 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.

Stakeholder Proceeding on Gas Competition, BGSS—In February 2023, the BPU announced that it would open a new docket to conduct a stakeholder proceeding regarding gas supply issues previously raised by competitive gas suppliers, including third-party suppliers’ participation in New Jersey gas distribution companies’ annual BGSS filings, and other aspects of the existing BGSS construct. In April-May 2023 the BPU Board conducted an initial stakeholder meeting and received written comments identifying any issues to be examined, presumably in a future portion of this proceeding following BPU Staff recommendation and BPU Board adoption. There has been no public activity in this matter since the submissions in May 2023.

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Gas Capacity Review—In September 2019, the BPU formally opened a stakeholder proceeding to explore gas capacity procurement service to all New Jersey natural gas customers. The BPU retained a consultant and in June 2022 accepted the consultant’s key finding that, through 2030, New Jersey’s firm gas capacity can meet firm demand under normal design day conditions. The only potential gas supply shortfall was found during extreme weather (i.e., a winter day that could be expected to occur only once in 90 years) and/or a “perfect storm,” which occurs when there is an outage on a transcontinental pipeline during a design day. The BPU noted that its consultant’s analysis supports the argument against the need for additional interstate pipeline capacity and also supports the BPU’s aggressive policy approach to reduce New Jersey’s overall reliance on fossil fuels and achieve the New Jersey governor’s goal of 100% clean energy by 2050.

Energy Efficiency, Triennial Review—During 2023, the BPU issued two Energy Efficiency Framework Orders which address, among other things, program administration and design, cost recovery and filing requirements, goals, a performance incentive mechanism, building decarbonization and demand response (DR), and required utilities to submit EE programs aligned with this framework.

In September 2023, the BPU directed utilities to apply for a six-month extension of the first triennial programs. PSE&G filed for its six-month extension of the existing program in November 2023, and filed its second triennial EE program proposal in December 2023. Both filings are subject to BPU approval.

BGS Process—In June 2023, New Jersey’s EDCs, including PSE&G, filed their annual joint proposal for the conduct of the 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 dc, 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 the 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 rates effective June 1, 2023. In November 2023, the BPU issued its decision to approve the joint EDCs’ proposal regarding the BGS auction process, including approving the EDCs’ proposed DCFC BGS rate pilot programs.

EV Activity—Consistent with the policy set forth in New Jersey’s EMP, the BPU has supported electrification of the transportation sector. EDCs in New Jersey, including PSE&G, are making investments, approved by the BPU for recovery in rates, initially focused on light duty vehicles, such as preparatory work to deliver infrastructure to the EV charging point. In June 2021, the BPU issued an initial straw proposal for the establishment of an EV infrastructure ecosystem for medium-and heavy-duty EVs in New Jersey, and conducted a series of stakeholder meetings to discuss that ecosystem. In December 2022, the BPU issued a revised straw proposal for public comment. Although we cannot predict the outcome of the stakeholder process, we anticipate that this effort will result in opportunities for EDCs to target infrastructure investments for the medium- and heavy-duty EV market.

Grid Modernization—In October 2021, the BPU commenced a stakeholder proceeding to develop and implement a systemic Grid Modernization plan in accordance with strategies outlined in the New Jersey EMP. The BPU retained a consultant that gathered detailed and comprehensive information from New Jersey’s EDCs, including PSE&G, regarding resource issues and policy changes needed to interconnect the clean energy capacity required under state policy. In June 2022, the BPU’s consultant issued a draft report with its findings and recommendations to update the BPU’s interconnection regulations and processes. The BPU is currently considering revising its interconnection rules to speed up the interconnection of renewable resources to the distribution grid. We cannot predict the impact on our business or results of operations from this Grid Modernization plan or any laws, rules or regulations promulgated as a result thereof, particularly as they may relate to PSE&G’s electric distribution assets.

New Jersey Solar Initiatives—In July 2021, the BPU issued an order formally establishing the Successor Solar Incentive (SuSI) Program, heavily drawing upon the predecessor Transition Renewable Energy Certificates program, to serve as the permanent program for providing solar incentives to qualified solar electric generation facilities. New Jersey’s EDCs role in the program is to acquire all of the Solar Renewable Energy Certificates-II received each year by eligible solar generation projects and each EDC may recover from its customers the reasonable and prudent costs incurred in the disposition of SuSI obligations. During 2023, the BPU rejected the first round of bids for the SuSI program projects as they exceeded pre-determined, confidential price caps. In September 2023, the BPU issued an Order opening a second round of solicitations which closes in February 2024.

In August 2023, the BPU established a permanent Community Solar Energy Program (CSEP) including eligibility requirements, registration processes, the implementation of consolidated billing for the benefit of project developers and participants and allowing for the electric and natural gas utilities to recover costs related to implementing and administering the CSEP program. The program does not include the opportunity for utilities to develop or operate CSEP projects.

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Cybersecurity Regulation

Federal—NERC Critical Infrastructure Protection standards establish cybersecurity and physical security protections for critical systems and facilities. These standards are also designed to promote coordination, threat sharing and interaction between utilities and various government agencies regarding potential cyber and physical threats against the nation’s electric grid. The scope of the Critical Infrastructure Protection standards is limited to Bulk Electric System (BES) Cyber Systems that would impact the reliable operation of the BES. PSE&G is obligated to comply with the NERC Critical Infrastructure Protection standards.

NERC Critical Infrastructure Protection standards do not apply to nuclear facilities which are instead governed by the NRC for purposes of physical and cyber security. NRC has a number of risk-informed, performance-based security programs in place to effectively protect U.S. commercial nuclear facilities. NRC has existing requirements, effective processes, and the expertise to regulate and inspect cybersecurity to ensure the federal requirements are met. NERC continues to examine revising criteria for low-impact cyber systems, which could result in expanding the Critical Infrastructure Protection standards to a larger set of applicable cyber assets.

NRC requires operating nuclear power plant licensee and license applicants to ensure that digital computer and communication systems associated with a nuclear power plant’s safety, security, and emergency preparedness functions are protected from cyberattacks. As a result, computer systems at operating power plants that monitor and control safety systems and help the reactor operate are isolated from external communications. Security systems that provide safeguards of the facility are also isolated from external communications, including the Internet.

NRC’s Office of Nuclear Security and Incident Response established the Cyber Security Branch (CSB) to strengthen internal governance of the agency’s regulatory activities. The CSB plans, coordinates, and manages agency activities related to cybersecurity for NRC applicants and licensees, such as security programs’ development and policy enhancements to prevent malevolent cyber acts against NRC-licensed facilities. The CSB’s cybersecurity-related responsibilities include developing rules and guidance, reviewing licensing actions, developing policy enhancements, and overseeing NRC-licensed facilities.

NRC regularly monitors the threats associated with cybersecurity, including potential threats against NRC-licensed facilities. Within the CSB there is a cyber assessment team that assesses real-world cyber events at NRC-licensed facilities. The team evaluates whether an identified threat could impact licensed facilities and makes recommendations for NRC actions and communications to the licensees. Furthermore, the NRC has established liaison relationships with the intelligence and law enforcement communities to include the National Counterterrorism Center, the U.S. Department of Homeland Security’s (DHS) Computer Emergency Response Team, and the Federal Bureau of Investigation.

The Transportation Security Administration, an agency of the U.S.DHS, has issued multiple security directives since May 2021 designed to mitigate cybersecurity threats to natural gas pipelines.

State—The BPU requires utilities, including PSE&G, to, among other things, implement a cybersecurity program that defines and implements organizational accountabilities and responsibilities for cyber risk management activities, and establishes policies, plans, processes and procedures for identifying and mitigating cyber risk to critical systems. Additional requirements of this order include, but are not limited to (i) annually inventorying critical utility systems; (ii) annually assessing risks to critical utility systems; (iii) implementing controls to mitigate cyber risks to critical utility systems; (iv) monitoring log files of critical utility systems; (v) reporting cyber incidents to the BPU; and (vi) establishing a cybersecurity incident response plan and conducting biennial exercises to test the plan. In addition, New York’s Stop Hacks and Improve Electronic Data Security (SHIELD) Act, which became effective in March 2020, requires businesses that own or license computerized data that includes New York State residents’ private information to implement reasonable safeguards to protect that information.

ENVIRONMENTAL MATTERS

We are subject to federal, state and local laws and regulations with regard to environmental matters. Our associated obligations change as legislatures and regulators pass new laws and regulations and amend existing ones. Therefore, it is difficult to project future costs of compliance and their impact on competition. Capital costs of complying with known pollution control requirements are included in our estimate of construction expenditures in Item 7. MD&A—Capital Requirements. The costs of compliance associated with any new requirements that may be imposed by future regulations are not known but may be material.

For additional information related to environmental matters, including proceedings not discussed below, as well as anticipated expenditures for installation of compliance technology, hazardous substance liabilities and fuel and waste disposal costs, see Item 1A. Risk Factors and Item 8. Note 13. Commitments and Contingent Liabilities.

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Air Pollution Control

Our facilities are subject to federal, state and local regulation that requires controls of emissions from sources of air pollution and imposes recordkeeping, reporting and permit requirements.

Water Pollution Control

The Federal Water Pollution Control Act prohibits the discharge of pollutants from point sources to water, except pursuant to a duly issued permit. These permits must generally be renewed every five years. Applicable regulations also impose obligations on facility operators like PSEG Power to install certain technology to treat their discharges to ensure discharges meet certain water quality requirements.

The Environmental Protection Agency’s (EPA) Clean Water Act (CWA) Section 316(b) rule establishes requirements for the regulation of cooling water intakes at existing power plants, such as Salem.

Hazardous Substance Liability

PSEG’s operations involve substances and byproducts classified by environmental regulations as hazardous. These regulations impose handling, storage and disposal requirements for hazardous materials. They also impose liability for damages to the environment, including cash penalties.

Site Remediation—Federal and state environmental laws and regulations require the cleanup of discharged hazardous substances. They authorize the EPA, the New Jersey Department of Environmental Protection (NJDEP) and private parties to commence lawsuits to compel clean-ups or seek reimbursement for such remediation. The clean-ups can be more complicated and costly when the hazardous substances are in or under a body of water. Clean-up obligations may be imposed regardless of the absence of fault, contractual agreements between parties, or the legality of activities at the time of discharge.

Natural Resource Damages—Federal and state environmental laws and regulations authorize damage assessments against persons who have caused an injury to natural resources through the discharge of a hazardous substance. The NJDEP requires persons conducting remediation to address such injuries through restoration or damage assessments.

Fuel and Waste Disposal

Nuclear Fuel Disposal—The federal government has entered into contracts with the operators of nuclear power plants for transportation and ultimate disposal of spent nuclear fuel. Under the Nuclear Waste Policy Act of 1982 (NWPA), nuclear plant owners are required to contribute to a Nuclear Waste Fund to pay for this service. Since May 2014, the nuclear waste fee rate has been zero. No assurances can be given that this fee will not be increased in the future. The NWPA allows spent nuclear fuel generated in any reactor to be stored in reactor facility storage pools or in Independent Spent Fuel Storage Installations located at reactors or away from reactor sites.

We have on-site storage facilities that are expected to satisfy the storage needs of Salem 1, Salem 2, Hope Creek, Peach Bottom 2 and Peach Bottom 3 through the end of their operating licenses.

Low-Level Radioactive Waste—As a by-product of their operations, nuclear generation units produce low-level radioactive waste. Such waste includes paper, plastics, protective clothing, water purification materials and other materials. These waste materials are accumulated on site and disposed of at licensed permanent disposal facilities. New Jersey, Connecticut and South Carolina have reached an agreement that gives New Jersey nuclear generators continued access to a waste disposal facility which is owned by South Carolina. We believe that this agreement will provide for adequate low-level radioactive waste disposal for Salem and Hope Creek through the end of their current licenses including full decommissioning, although no assurances can be given. Low-Level Radioactive Waste is periodically being shipped to the South Carolina waste disposal facility from Salem and Hope Creek. Additionally, there are on-site storage facilities for Salem, Hope Creek and Peach Bottom, which we believe have the capacity for at least five years of temporary storage for each facility.

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INFORMATION ABOUT OUR EXECUTIVE OFFICERS (PSEG)

Name

Age as of

December 31, 2023

Office

Effective Date
First Elected to
Present Position

Ralph A. LaRossa

Chair of the Board (COB), President and Chief Executive Officer (CEO) - PSEG

January 2023 to present

President and CEO -PSEG

September 2022 to present

Chief Operating Officer (COO) - PSEG

January 2020 to August 2022

COB and CEO - PSE&G

September 2022 to present

COB, President and CEO - PSEG Power

May 2023 to present

COB and CEO - PSEG Power

September 2022 to May 2023

COB and CEO - Energy Holdings

September 2022 to present

COB, CEO and President - Services

September 2022 to present

President and COO - PSEG Power

October 2017 to August 2022

President and COO - PSE&G

October 2006 to October 2017

COB - PSEG Long Island LLC

December 2020 to August 2022

Daniel J. Cregg

Executive Vice President (EVP) and Chief Financial Officer (CFO) - PSEG

October 2015 to present

EVP and CFO - PSE&G

October 2015 to present

EVP and CFO - PSEG Power

October 2015 to present

Kim C. Hanemann

President and COO - PSE&G

June 2021 to present

Senior Vice President (SVP) and COO - PSE&G

January 2020 to June 2021

SVP - Electric Transmission and Distribution - PSE&G

September 2018 to January 2020

SVP - Delivery, Projects and Construction - PSE&G

July 2014 to September 2018

Tamara L. Linde

EVP and General Counsel - PSEG

July 2014 to present

EVP and General Counsel - PSE&G

July 2014 to present

EVP and General Counsel - PSEG Power

July 2014 to present

Charles V. McFeaters

President and Chief Nuclear Officer - PSEG Nuclear LLC

May 2023 to present

SVP - Nuclear Operations - PSEG Nuclear LLC

November 2020 to May 2023

Vice President (VP) - Salem Generating Station - PSEG Nuclear LLC

October 2016 to November 2020

Sheila J. Rostiac

SVP - Human Resources, Chief Human Resources and Chief Diversity Officer - Services

January 2020 to present

SVP - Human Resources and Chief Human Resources Officer - Services

September 2019 to January 2020

VP - Talent, Development and Diversity

October 2012 to September 2019

Richard T. Thigpen

SVP - Corporate Citizenship - Services

July 2018 to present

VP - State Government Affairs - Services

March 2007 to July 2018

Rose M. Chernick

VP and Controller - PSEG

March 2019 to present

VP and Controller - PSE&G

March 2019 to present

VP and Controller - PSEG Power

March 2019 to present

VP-Finance, Corporate Strategy and Planning - Services

November 2017 to March 2019

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ITEM 1A. RISK FACTORS

The following factors should be considered when reviewing our business. These factors 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.

GENERAL OPERATIONAL AND FINANCIAL RISKS

Inability to successfully develop, obtain regulatory approval for, or construct T&D, and our nuclear generation projects could adversely impact our businesses.

Our business plan calls for extensive investment in capital improvements and additions, including the construction of T&D facilities, modernizing and expanding existing infrastructure pursuant to investment programs that provide for current recovery in rates, and our CEF programs, which include providing incentives for customers to install high-efficiency equipment at their premises, constructing EV infrastructure, and implementing our smart meter program. Currently, we have several significant projects underway or being contemplated.

The successful construction and development of these projects will depend, in part, on our ability to:

•obtain necessary governmental and regulatory approvals;

•obtain environmental permits and approvals;

•obtain community support for such projects to avoid delays in the receipt of permits and approvals from regulatory authorities;

•obtain customer support for investments made at their premises;

•obtain property/land rights in property-constrained areas and at a reasonable cost;

•complete such projects within budgets and on commercially reasonable terms and conditions;

•complete supporting information technology (IT), cybersecurity and physical security upgrades;

•obtain any necessary debt financing on acceptable terms and/or necessary governmental financial incentives;

•ensure that contracting parties, including suppliers, perform under their contracts in a timely and cost-effective manner; and

•timely recovery of these investments through rates.

Failure to obtain regulatory or other approvals, delays, cost escalations or otherwise unsuccessful construction and development could materially affect our financial position, results of operations and cash flows.

Macroeconomic considerations, including inflationary levels, gas and electric supply prices that are passed through to customers and other pressures could factor into our regulators’ assessment in approving the size, duration and timing of cost recovery of certain of these programs. Further, certain negative public and political views on natural gas could result in diminishing political support for utility investments in gas infrastructure.

In addition, the successful operation of new facilities or transmission or distribution projects is subject to risks relating to supply interruptions; labor availability, work stoppages and labor disputes; weather interferences; unforeseen engineering and environmental problems, including those related to climate change; opposition from local communities, and the other risks described herein.

Any of these risks could cause the amounts of our investments and/or our return on these investments to be lower than expected, which could adversely impact our financial condition and results of operations through lower investment opportunities and/or lower returns.

We are subject to physical, financial and transition risks related to climate change, including potentially increased legislative and regulatory burdens and changing customer preferences, and we may be subject to lawsuits, all of which could impact our businesses and results of operations, as well as our ability to implement our clean energy strategy.

Climate change may increasingly drive change to existing or additional legislation and regulation that may impact our business and shape our customers’ energy preference and sustainability goals. While the CIP protects PSE&G’s margin variances against changes in customer usage of gas and electricity, customer demand for natural gas could decrease as a result of changing customer preferences favoring electrification and advanced technologies that offer energy efficient options. Electric usage could also be impacted by greater adoption of EVs, installation of distributed energy resources, such as behind the meter solar,

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installation of more energy efficient equipment, flexible load and/or energy storage, and other advances in technology. Further, climate change may adversely impact the economy and reduced economic and consumer activity in our service areas could lower demand for electricity and gas we deliver. Any one or all of these factors could impact the need to invest in our electric and gas T&D systems and, therefore, the rate of growth of our company.

Severe weather or acts of nature, including hurricanes, winter storms, earthquakes, floods, wildfires and other natural disasters can stress systems, disrupt operation of our facilities and cause service outages, and property damage that require incurring additional expenses. These and other physical changes could result in changes in customer demand, increased costs associated with repairing and maintaining generation facilities and T&D systems, resulting in increased maintenance and capital costs (and potential increased financing needs), increased regulatory oversight, and lower customer satisfaction. Where recovery of costs to restore service and repair damaged equipment and facilities is available, any determination by the regulator not to permit timely and full recovery of the costs incurred could have a material adverse effect on our businesses, financial condition, results of operations and prospects.

To the extent financial markets view climate change and greenhouse gas (GHG) emissions as a financial risk, our ability to access capital markets could be negatively affected or cause us to receive less than favorable terms and conditions.

Climate change-related political action and state and federal policy goals, including but not limited to those related to energy efficient targets, solar targets, energy storage targets, encouragement of electrification through EV adoption, policies to restrict the use of natural gas in new or existing homes and businesses, or encourage electrification of end use equipment currently fueled by natural gas, and the associated legislative and regulatory responses, may create financial risk as our operations may be subject to additional regulation at either the state or federal level in the future. Increased regulation of GHG emissions could impose significant additional costs on our electric and natural gas operations, our suppliers and ultimately, our customers. Developing and implementing plans for compliance with GHG emissions reduction, clean/renewable energy requirements, or for achieving voluntary climate commitments can lead to additional capital, personnel, and Operation and Maintenance (O&M) expenditures and could significantly affect the economic position of existing operations and proposed projects. If our regulators do not allow us to recover all or a part of the cost of capital investment or the O&M costs incurred to comply with increasingly rigorous regulatory mandates, it could have a material adverse effect on our results of operations, financial condition or cash flows. On the other hand, in the event that the political, policy, regulatory or legislative support for clean energy projects declines, the benefits or feasibility of certain investments we may have made in such projects, including those in the development stage, may be reduced.

We may be subject to climate change lawsuits that may seek injunctive relief, monetary compensation, penalties, and punitive damages, including but not limited to, for liabilities for damages related to mitigate harm caused by climate change. An adverse outcome could require substantial capital expenditures and possibly require payment of substantial penalties or damages. Defense costs associated with such litigation can also be significant and could affect results of operations, financial condition or cash flows if such costs are not recovered through regulated rates.

Further, our business is subject to policy, regulatory, technology and economic uncertainties and contingencies, including regulatory approvals required for various of our clean energy initiatives, many of which are beyond our control and may affect our ability to implement our clean energy strategy and initiatives and achieve our goal of net zero GHG emissions by 2030 for Scopes 1 and 2 emissions, or other GHG emissions reduction or climate-related goals that we may set from time to time, in a cost-effective manner or at all.

We may be adversely affected by asset and equipment failures, accidents, critical operating technology or business system failures, natural disasters, severe weather events, acts of war or terrorism or other acts of violence, sabotage, physical attacks or security breaches, cyberattacks, or other incidents, including pandemics such as the coronavirus pandemic, that impact our ability to provide safe and reliable service to our customers and remain competitive and could result in substantial financial losses.

The success of our businesses is dependent on our ability to continue providing safe and reliable service to our customers while minimizing service disruptions. We are exposed to the risk of asset and equipment failures, gas explosions, accidents, natural disasters, severe weather events, acts of war or terrorism or other acts of violence, including active shooter situations, sabotage, physical attacks or security breaches, cyberattacks or other incidents, which could result in damage to or destruction of our substations or other facilities or infrastructure, or damage to persons or property and to electric and gas supply interruptions. Further, a major failure of availability or performance of a critical operating technology or business system, and inadequate preparation or execution of business continuity or disaster recovery plans for the loss of one or several critical systems, could result in extended disruption to operations or business processes, damage to systems and/or loss of data. We have historically benefited from access to mutual aid, a voluntary and reciprocal arrangement with other utilities that provides access to a trained and flexible labor force which has helped to reduce outage restoration times during extreme weather events. There is no guarantee that we will have continued access to mutual aid as the utility industry consolidates and the frequency of severe weather events rises.

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We are also exposed to the risk of pandemics, such as the coronavirus pandemic, which could result in service disruptions and delays or otherwise impair our ability to timely provide service to our customers or complete our investment projects. In response to the coronavirus pandemic, New Jersey and the BPU implemented a number of expanded customer protection measures, such as an extended moratorium on shut-offs of residential service for non-payment, and more extensive processes to be taken prior to any shut-off of service. These actions negatively affected customer payment patterns, leading to an elevated aged accounts receivable balance. Our ability to manage our accounts receivable balance, and obtain recovery in rates for our carrying costs and any associated bad debts could have a material impact on our business.

These events could result in increased political, economic, financial and insurance market instability, a lack of available insurance and volatility in power and fuel markets, which could materially adversely affect our business and results of operations, including our ability to access capital on terms and conditions acceptable to us.

In addition, the effects of climate change will have increased the physical risks to our facilities and operations resulting from such climate hazards as more severe weather events (extreme wind, rainfall and flooding), such as experienced from Superstorm Sandy and Tropical Storms Isaias and Ida, sea level rise, and extreme heat.

Any of the issues described above, if experienced at our facilities or otherwise in our business, or by others in our industry, could adversely impact our revenues; increase costs to repair and maintain our systems; subject us to potential litigation and/or damage claims, fines or penalties; and increase the level of oversight of our utility and generation operations and infrastructure through investigations or through the imposition of additional regulatory or legislative requirements. Such actions could adversely affect our costs, competitiveness and future investments, which could be material to our financial position, results of operations and cash flow. For our T&D business, the cost of storm restoration efforts may not be fully recoverable through the regulatory process. In addition, the inability to restore power to our customers on a timely basis could result in negative publicity and materially damage our reputation.

Any inability to recover the carrying amount of our long-lived assets could result in future impairment charges which could have a material adverse impact on our financial condition and results of operations.

Long-lived assets represent approximately 75% and 82% of the total assets of PSEG and PSE&G, respectively, as of December 31, 2023. Management evaluates long-lived assets for impairment whenever events or changes in circumstances, such as significant adverse changes in regulation, including a disallowance of certain costs, a potential sale or disposition of an asset significantly before the end of its useful life, business climate or market conditions, including prolonged periods of adverse commodity and capacity prices, could potentially indicate an asset’s or group of assets’ carrying amount may not be recoverable. Significant reductions in our expected revenues or cash flows for an extended period of time resulting from such events could result in future asset impairment charges, which could have a material adverse impact on our financial condition and results of operations.

Disruptions or cost increases in our supply chain, including labor shortages, could materially impact our business.

The supply chain of goods and services is currently being negatively impacted by several factors, including manufacturing labor shortages, domestic and international shipping constraints, increases in demand, and shortages of raw materials and specialty components. As a result, we are seeing price increases in some areas and delivery delays of certain goods. These factors have increased our costs and have the potential to impact our operations. We cannot currently estimate the potential impact of continued supply chain disruptions but they could materially impact our business and results of operations.

Inability to maintain sufficient liquidity in the amounts and at the times needed or access sufficient capital at reasonable rates or on commercially reasonable terms could adversely impact our business.

Funding for our investments in capital improvement and additions, scheduled payments of principal and interest on our existing indebtedness and the extension and refinancing of such indebtedness has been provided primarily by internally-generated cash flow and external debt financings. We have significant capital requirements and depend on our ability to generate cash in the future from our operations and continued access to capital and bank markets to efficiently fund our cash flow needs. Our ability to generate cash flow is dependent upon, among other things, industry conditions and general economic, financial, competitive, legislative, regulatory and other factors. The ability to arrange financing and to refinance existing debt and the costs of such financing or refinancing depend on numerous factors including, among other things:

•general economic and capital market conditions, including but not limited to, prevailing interest rates;

•the availability of credit from banks and other financial institutions;

•tax, regulatory and securities law developments;

•for PSE&G, our ability to obtain necessary regulatory approvals for the incurrence of additional indebtedness;

•investor confidence in us and our industry;

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•our current level of indebtedness and compliance with covenants in our debt agreements;

•the success of current projects and the quality of new projects;

•our current and future capital structure;

•our financial performance and the continued reliable operation of our business; and

•maintenance of our investment grade credit ratings.

Market disruptions, such as economic downturns experienced in the U.S. and abroad, the bankruptcy of an unrelated energy company or a systemically important financial institution, changes in market prices for electricity and gas, and actual or threatened acts of war or terrorist attacks, may increase our cost of borrowing or adversely affect our ability to access capital. As a result, no assurance can be given that we will be successful in obtaining financing for projects and investments, extending or refinancing maturing debt or meeting our other cash flow needs on acceptable terms or at all, which could materially adversely impact our financial position, results of operations and future growth.

During periods of rising energy prices, hedged positions could be out-of-the-money, increasing PSEG Power’s collateral requirements. In addition, if PSEG Power were to lose its investment grade credit rating from S&P or Moody’s, it would be required under certain agreements to provide a significant amount of additional collateral in the form of letters of credit or cash, which would have a material adverse effect on our liquidity and cash flows.

Cybersecurity attacks or intrusions or other disruptions to our IT, operational or other systems could adversely impact our businesses.

Cybersecurity threats to the energy market infrastructure are increasing in sophistication, magnitude and frequency, particularly with the regularity of virtual operations. Because of the inherent vulnerability of infrastructure and technology and operational systems to disability or failure due to hacking, viruses, malicious or destructive code, phishing and other social engineering attacks, denial of service attacks, ransomware, acts of war or terrorism, or other cybersecurity incidents, we face increased risk of cyberattack. We rely on information and operational technology systems and network infrastructure to operate our generation and T&D systems. We also store sensitive data, intellectual property and proprietary or personally identifiable information regarding our business, infrastructure, employees, shareholders, customers and vendors on our IT systems and conduct power marketing and hedging activities. In addition, the operation of our business is dependent upon the IT systems of third parties, including our vendors, regulators, RTOs and ISOs, among others. Our and third-party operational and IT systems and products may be vulnerable to cybersecurity attacks involving fraud, malice or oversight on the part of our employees, other insiders or third parties, whether domestic or foreign sources. Further, new types of cyberattacks, whether directed at our own infrastructure and technology and operational systems or that of third parties, may be generated or enhanced through the use of Artificial Intelligence (AI). A successful cybersecurity attack may result in unauthorized use of our systems to cause disruptions at a third party. Cybersecurity risks to our operations include:

•disruption of the operation of our assets, the fuel supply chain, the power grid and gas T&D,

•theft of confidential company, employee, shareholder, vendor or customer information, and critical energy infrastructure information, which may cause us to be in breach of certain covenants and contractual or legal obligations and pose risk to our system and our customers,

•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 and our third-party vendors have been and will continue to be subject to cybersecurity attacks, including but not limited to ransomware, denial of service, business email compromises, and malware attacks. To date, there has been no material impact or reasonably likely material impact on our business strategy, results of operations or financial condition from these attacks or other cybersecurity incidents, including as a result of prior cybersecurity incidents. However, we may be unable to prevent all such attacks in the future from having such a material impact as such attacks continue to increase in sophistication and frequency. If a significant cybersecurity event or breach occurs 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 if determined that we were in non-compliance with existing laws and regulations, significant litigation costs, increased costs to finance our businesses, negative publicity, damage to our reputation and loss of confidence from our customers, regulators, investors, vendors and employees. The misappropriation, corruption or loss of personally identifiable information and other confidential data from us or one of our vendors could lead to significant breach notification expenses, mitigation expenses such as credit monitoring, and legal and regulatory fines and penalties. Moreover, new or updated security laws or regulations, including laws and regulations that respond to evolving application of AI, or unforeseen threat sources could require changes in current measures taken by us and our business operations, which could result in increased costs and

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adversely affect our financial statements. 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. The amount and scope of insurance we maintain against losses that result from cybersecurity incidents may not be sufficient to cover losses or adequately compensate for resulting business disruptions. For a discussion of state and federal cybersecurity regulatory requirements and information regarding our cybersecurity program, see Item 1C. Cybersecurity.

A material shift away from natural gas toward increased electrification and a reduction in the use of natural gas as a result of decarbonization measures could adversely impact our gas business and ability to execute on our overall PSE&G business strategy.

Various jurisdictions outside of New Jersey have enacted prohibitions or restrictions on the use and consumption of natural gas and the BPU has commenced stakeholder proceedings regarding the Future of Natural Gas as required by the New Jersey governor’s EO issued in 2023. The CIP protects PSE&G’s margin variances against changes in customer usage of gas and electricity, but not against a decrease in the gas customer base (number of customers on the system). If New Jersey were to enact similar prohibitions or restrictions, a reduction in the use of natural gas could lead to a reduction in the gas customer base, higher customer rates for those customers who remain, and a diminished need for gas infrastructure, which could potentially cause substantial investment value of gas assets to be stranded and removed from our rate base, resulting in a reduction in associated rate recovery. Our inability to recover through rates our investments into the natural gas system, while still ensuring gas system safety and reliability, could materially affect our financial condition, results of operations, liquidity, and cash flows. Further, these industry changes, costs associated with complying with new regulatory developments and initiatives and with technological advancements could materially affect our financial condition, results of operations, liquidity, and cash flows.

If the above changes occurred, that would also require investment in the electric T&D system to accommodate higher loads. In addition, in order to enable the New Jersey clean energy economy, sustained grid modernization will be required to accommodate increased EE, EV infrastructure, increased penetration of distributed energy resources on the electric system, such as on-site solar generation and also anticipated increased deployment of energy storage, fuel cells, and DR technologies. If these changes progress rapidly in the near-term, our business model and our ability to execute on our overall PSE&G business strategy could be materially impacted.

Failure to attract and retain a qualified workforce could have an adverse effect on our business.

Certain events such as an aging workforce looking to retire without an opportunity to transfer knowledge to a successor, inadequate workforce plans and replacements, lack of skill set to meet current and evolving business needs, a culture that does not foster inclusion leading to turnover, acts of violence in the workplace, inadequate training and a workforce that is not engaged may lead to operating challenges, safety concerns and increased costs. The challenges include loss of knowledge and a lengthy time period associated with skill development, increased turnover, costs for contractors to replace employees, poor productivity, and a lack of innovation. Specialized knowledge and experience are required of employees across PSEG and its affiliates. There is competition for these skilled employees. Failure to hire and adequately train and retain employees, including the transfer of significant historical knowledge and expertise to new employees, may adversely affect our results of operations, financial position and cash flows.

Increases in the costs of equipment and materials, fuel, services and labor could adversely affect our operating results.

Higher costs from suppliers of equipment and materials, fuel, services and labor costs to attract and retain our workforce, could lead to increased costs, which could reduce our earnings. Also, seeking recovery of higher costs in future distribution base rate cases could pressure customer rates, resulting in a potentially adverse outcome of such proceedings, or in other proceedings, including the proposal of certain investment programs or other proceedings that impact customer rates.

Covenants in our debt instruments and credit agreements may adversely affect our business.

PSEG’s and PSE&G’s debt instruments contain events of default customary for financings of their type, including cross accelerations to other debt of that entity. PSEG’s, PSE&G’s and PSEG Power’s bank credit agreements contain events of default customary for financings of their type, including cross defaults and accelerations and, in the case of PSEG’s and PSEG Power’s bank credit agreements, certain change of control events. PSEG’s, PSE&G’s and PSEG Power’s bank credit agreements, contain certain limitations on the incurrence of liens and PSEG Power’s bank credit agreements also contain limitations on the incurrence of certain subsidiary debt. The PSEG Power term loan agreement contains a change-of-control clause, which includes PSEG Power ceasing to be a wholly owned subsidiary of PSEG. Our ability to comply with these covenants may be affected by events beyond our control. If we fail to comply with the covenants and are unable to obtain a waiver or amendment, or a default exists and is continuing under such debt, the lenders or the holders or trustee of such debt, as applicable, could give notice and declare outstanding borrowings and other obligations under such debt immediately due and payable. We may not be able to obtain waivers, amendments or alternative financing, or if obtainable, it could be on terms that

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are not acceptable to us. Any of these events could adversely impact our financial condition, results of operations and cash flows.

Financial market performance directly affects the asset values of our defined benefit plan trust funds and Nuclear Decommissioning Trust (NDT) Fund. Market performance and other factors could decrease the value of trust assets and could result in the need for significant additional funding.

The performance of the financial markets will affect the value of the assets that are held in trust to satisfy our future obligations under our defined benefit plans and to decommission our nuclear generating plants. A decline in the market value of the defined benefit plan trust funds could increase our pension plan funding requirements and result in increased pension costs in future years. The market value of our defined benefit plan trusts could be negatively impacted by adverse financial market conditions that reduce the return on trust assets, decreased interest rates used to measure the required minimum funding levels, and future government regulation. Additional funding requirements for our defined benefit plans could be caused by changes in required or voluntary contributions, an increase in the number of employees becoming eligible to retire and changes in life expectancy assumptions. A decline in the market value of our NDT Fund could increase PSEG Power’s funding requirements to decommission its nuclear plants. An increase in projected costs could also lead to additional funding requirements for our decommissioning trust. Failure to manage adequately our investments in our defined benefit plan trusts and NDT Fund could result in the need for us to make significant cash contributions in the future to maintain our funding at sufficient levels, which would negatively impact our results of operations, cash flows and financial position.

If we are unable to extend certain significant contracts on terms acceptable to us, this may negatively affect our financial condition and operating results

We are party to several contracts from which we derive significant revenues. PSEG Power sells wholesale natural gas, primarily through a full-requirements BGSS contract with PSE&G to meet the needs of PSE&G’s default gas supply service customers. In 2022, the BPU approved an extension of the long-term BGSS contract to March 31, 2027, and thereafter the contract remains in effect unless terminated by either party with a two-year notice. PSEG LI has an OSA with LIPA to operate LIPA’s electric T&D system in Long Island. The OSA continues through 2025, but can be extended by mutual agreement of the parties. Further, PSEG Power provides fuel procurement and power management services to LIPA under separate agreements that expire at the end of 2025. It is uncertain whether any of these contracts and agreements will be extended on terms acceptable to us or at all, which may negatively affect our financial condition and operating results. For additional information, see Item 1. Business—PSEG Power & Other.

Artificial Intelligence is an emerging area of technology that has the potential to impact various aspects of our business operations and customer interactions.

The development, adoption, and use for generative AI technologies are still in their early stages and ineffective or inadequate AI development or deployment practices by PSEG or third-party vendors could result in unintended consequences. We contract third-party vendors that use AI in products and/or services they provide and we may not have full control or visibility over the quality, performance, security or compliance of the products and services that incorporate AI-related technology. AI algorithms that we or our third-party vendors use may be flawed or may be based on datasets that are biased or insufficient. These limitations or failures could result in reputational damage and legal liabilities. Developing, testing, and deploying resource-intensive AI systems may require additional investment and increase our costs. In addition, the evolving nature of AI may cause new laws and regulations to be enacted which may require significant resources to modify and maintain business practices to comply with the new laws and regulations, the nature of which cannot be determined at this time. Further, inaccurate results generated as a result of our employees’, contractors’ or vendors’ use of generative AI technologies could lead to operational interruptions or reputational harm.

RISKS RELATED TO OUR GENERATION BUSINESS

Fluctuations in the wholesale power and natural gas markets could negatively affect our financial condition, results of operations and cash flows.

In the competitive markets where we operate, natural gas prices have a major impact on the price that generators receive for their output and participants are not guaranteed any specific rate of return on their capital investments. Recently, the natural gas market and, therefore, energy markets have become more volatile due to higher domestic demand, increased natural gas exports and impacts from the global liquefied natural gas market, among other things. The price of natural gas is the primary driver of energy pricing in PJM. As such, the volatility in the natural gas market and potential lower natural gas prices may impact our results of operations and cash flows. Lower natural gas prices result in lower electricity prices, which reduce our margins where our nuclear generation costs may not have declined similarly.

Changes in prevailing market prices below the PTC threshold could have a material adverse effect on our financial condition and results of operations. Factors that may cause market price fluctuations include:

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•increases and decreases in generation capacity, including the addition of new supplies of power as a result of the development of new power plants, expansion of existing power plants or additional transmission capacity;

•severe weather conditions;

•power supply disruptions, including power plant outages and transmission disruptions;

•climate change, and weather conditions, particularly unusually mild summers or warm winters in our market areas;

•seasonal fluctuations;

•economic and political conditions that could negatively impact the demand for power or PTCs on our nuclear generation units;

•changes in the supply of, and demand for, energy commodities;

•development of new fuels or new technologies for the production or storage of power;

•incurring penalties due to generation performance failure when called on by PJM during emergency situations;

•federal and state regulations and actions of PJM and changing PJM market rules; and

•federal and state power, market and environmental regulation and legislation, including financial incentives for new renewable energy generation capacity that could lead to oversupply and price suppression.

Our generation business currently involves the establishment of forward sale positions in the wholesale energy markets on long-term and short-term bases. To the extent that we have produced or purchased energy in excess of our contracted obligations, a reduction in market prices could reduce profitability. Conversely, to the extent that we have contracted obligations in excess of energy we have produced or purchased, an increase in market prices could reduce profitability. If the strategy we utilize to hedge our exposure to these various risks or if our internal policies and procedures designed to monitor the exposure to these various risks are not effective, we could incur material losses. Our market positions can also be adversely affected by the level of volatility in the energy markets that, in turn, depends on various factors, including weather in various geographical areas, short-term supply and demand imbalances, and pricing differentials at various geographic locations. These risks cannot be predicted with certainty.

Increases in market prices also affect our ability to hedge generation output and fuel requirements as the obligation to post margin increases with increasing prices.

In addition, the volatility and potential for higher natural gas prices may have a material impact on collateral requirements related to the forward value of our open futures contracts. Higher collateral requirements reduce available short-term liquidity and increase working capital costs.

We may be unable to obtain an adequate nuclear fuel supply in the future.

We obtain substantially all of our nuclear fuel supply from third parties pursuant to arrangements that vary in term, pricing structure, firmness and delivery flexibility. Our fuel supply arrangements must be coordinated with storage services and other contracts to ensure that the nuclear fuel is delivered to our power plants at the times, in the quantities and otherwise in a manner that meets the needs of our generation portfolio and our customers. We must also comply with laws and regulations governing the transportation of such fuels.

We are exposed to increases in the price of nuclear fuel, and it is possible that sufficient supplies to operate our generating facilities profitably may not continue to be available to us. Significant changes in the price of nuclear fuel could affect our future results and impact our liquidity needs. In addition, we face risks with regard to the delivery to, and the use of nuclear fuel by, our power plants including the following:

•creditworthiness of third-party suppliers, defaults by third-party suppliers on supply obligations and our ability to replace supplies currently under contract may delay or prevent timely delivery;

•market liquidity for physical supplies of such fuels or availability of related services (e.g., fabrication) may be insufficient or available only at prices that are not acceptable to us;

•variation in the quality of such fuels may adversely affect our power plant operations;

•domestic and foreign legislative or regulatory actions or requirements may increase the cost of such fuels; and

•the loss of critical infrastructure, acts of war or terrorist attacks (including cybersecurity breaches) or catastrophic events such as fires, earthquakes, explosions, floods, severe storms or other similar occurrences could impede the delivery of such fuels.

Our nuclear units have a diversified portfolio of contracts and inventory that provide a substantial portion of our fuel raw

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material needs over the next several years. However, each of our nuclear units has contracted with a single fuel fabrication services provider, and transitioning to an alternative provider could take an extended period of time. This could have a material adverse impact on our business, the financial results of specific plants and on our results of operations.

Although our fuel contract portfolio provides a degree of hedging against these market risks, such hedging may not be effective and future increases in our fuel costs could materially and adversely affect our liquidity, financial condition and results of operations.

The introduction or expansion of technologies related to energy generation, distribution and consumption and changes in customer usage patterns could adversely impact us.

Federal and state incentives for the development and production of renewable sources of power have facilitated the penetration of competing technologies, such as wind, solar, and commercial-sized power storage. Additionally, the development of demand side management (DSM) and EE programs can impact demand requirements for some of our markets. The continued development of competing on-site power generation and storage technologies and significant development of DSM and EE programs could alter the market and price structure for power generation and could result in a reduction in load requirements, negatively impacting our financial condition, results of operations and cash flows. Federal or state laws mandating higher levels of efficiency in end-use electric devices or other improvements in, or applications of, technology could also lead to declines in per capita energy consumption.

Advances in distributed generation technologies, such as fuel cells, micro turbines, micro grids, windmills and net-metered solar installations, coupled with subsidies, may reduce the cost of alternative methods of delivering electricity to customers to a level that is competitive with that of most central station electric production. Large customers, such as universities and hospitals, continue to explore potential micro grid installation. Certain states are also considering mandating the use of power storage resources to replace uneconomic or retiring generation facilities. Such developments could (i) affect the price of energy, (ii) reduce energy deliveries as customer-owned generation becomes more cost-effective, (iii) require further improvements to our distribution systems to address changing load demands, and (iv) make portions of our transmission and/or distribution facilities obsolete prior to the end of their useful lives. These technologies could also result in further declines in commodity prices or demand for delivered energy.

Several states, cities and other stakeholders are also considering bans on natural gas connections to new buildings and transitioning away from natural gas in the future. Such actions could have a material adverse effect on our business.

Some or all of these factors could result in a lack of growth or decline in customer demand for electricity or natural gas or of customers, and may cause us to fail to fully realize anticipated benefits from significant capital investments and expenditures, which could have a material adverse effect on our financial position, results of operations and cash flows. These factors could also materially affect our results of operations, cash flows or financial positions through, among other things, reduced operating revenues, increased O&M expenses, and increased capital expenditures, as well as potential asset impairment charges or accelerated depreciation and decommissioning expenses over shortened remaining asset useful lives.

We are subject to third-party credit risk relating to our sale of nuclear generation output and purchase of nuclear fuel.

We sell generation output and buy fuel through the execution of bilateral contracts. We also seek to contract in advance for a significant proportion of our anticipated output capacity and fuel needs. These contracts are subject to credit risk, which relates to the ability of our counterparties to meet their contractual obligations to us. Any failure of these counterparties to perform could require PSEG Power to purchase or sell energy or fuel in the wholesale markets at less favorable prices and incur additional losses, which could have a material adverse impact on our results of operations, cash flows and financial position. In the spot markets, we are exposed to the risks of the default sharing mechanisms that exist in those markets, some of which attempt to spread the risk across all participants. Therefore, a default by a third party could increase our costs, which could negatively impact our results of operations and cash flows.

There may be periods when PSEG Power generation may not operate and/or may not be able to meet its commitments under forward sale obligations and PJM rules at a reasonable cost or at all.

A substantial portion of PSEG Power’s nuclear generation output has been sold forward under fixed price financial power sales contracts. Forward financial sales offset physical sales in the PJM RTO spot market. Our forward sales of energy and capacity assume sustained, acceptable levels of operating performance. Operations at any of our plants could degrade to the point where the plant has to shut down or operate at less than full capacity. Some issues that could impact the operation of our facilities are:

•breakdown or failure of equipment, IT, processes or management effectiveness;

•disruptions in the transmission of electricity;

•labor disputes or work stoppages;

•fuel supply interruptions;

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•limitations which may be imposed by environmental or other regulatory requirements; and

•operator error, acts of war or terrorist attacks (including physical or cybersecurity breaches) or catastrophic events such as fires, earthquakes, explosions, floods, severe weather or other similar occurrences.

Identifying and correcting any of these issues may require significant time and expense. Depending on the materiality of the issue, we may choose to close a plant rather than incur the expense of restarting it or returning it to full capacity.

Because the obligations under most of these forward sale agreements are not contingent on a unit being available to generate power, PSEG Power’s results of operations and cash flows are at risk even in the event of a plant outage, or a reduction in the available capacity of the unit. To the extent that PSEG Power does not meet its expected nuclear generation output, PSEG Power would be required to pay the difference between the market price and the contract price on its financial contracts without receiving the physical spot energy revenue or be required to purchase energy at higher prices to cover its shortfall. In addition, as capacity performance resources in PJM, PSEG’s nuclear units have been and will in the future be required to pay penalties if a forced outage at a plant occurs during a declared emergency event within PJM and that plant’s expected performance exceeds its actual performance during such event. The amount of such payments could be substantial and could have a material adverse effect on our financial condition, results of operations and cash flows. In addition, changing capacity performance rules and/or failure to follow existing rules – by PJM or market participants – creates regulatory uncertainty and reliability risk.

In addition, as market prices for energy and fuel fluctuate, our forward energy sale and forward fuel purchase contracts could require us to post substantial additional collateral, thus requiring us to obtain additional sources of liquidity during periods when our ability to do so may be limited.

REGULATORY, LEGISLATIVE AND LEGAL RISKS

PSE&G’s revenues, earnings and results of operations are dependent upon state laws and regulations that affect distribution and related activities.

PSE&G is subject to regulation by the BPU. Such regulation affects almost every aspect of its businesses, including its retail rates. Failure to comply with these regulations could have a material adverse impact on PSE&G’s ability to operate its business and could result in fines, penalties or sanctions. The retail rates for electric and gas distribution services are established in a distribution base rate proceeding and remain in effect until a new distribution base rate proceeding is filed and concluded. In December 2023, we filed a distribution base rate case, as required by the BPU. In addition, our utility has received approval for several clause recovery mechanisms, some of which provide for recovery of costs and earn returns on authorized investments in the periods between distribution base rate proceedings. These clause mechanisms require periodic updates to be reviewed and approved by the BPU and are subject to prudency reviews. Inability to obtain fair or timely recovery of all our costs pursuant to the distribution base rate case and/or these clause recovery mechanisms,, including a return of, or on, our investments in rates, could have a material adverse impact on our results of operations and cash flows. In addition, if legislative and regulatory structures were to evolve in such a way that PSE&G’s exclusive rights to serve its regulated customers were eroded, its future earnings could be negatively impacted.

PSE&G also is pursuing a number of opportunities to expand its products and services to customers to support clean energy goals. BPU approval is required for any new endeavor, and is not guaranteed. Rejection or delay of such filings could have an adverse impact on our future growth, or our standing with environmentally conscious investors or other stakeholders.

In September 2020, the BPU ordered the commencement of a comprehensive affiliate and management audit of PSE&G. The BPU also conducts periodic combined management/competitive service audits of New Jersey utilities related to affiliate standard requirements, competitive services, cross-subsidization, cost allocation and other issues. A finding by the BPU of non-compliance with these requirements could potentially impact our business, results of operations and cash flows. For information regarding PSE&G’s current affiliate and management audit, see Item 8. Note 13. Commitments and Contingent Liabilities. In addition, PSE&G procures the supply requirements of its default service BGSS gas customers through a full-requirements contract with PSEG Power. Government officials, legislators and advocacy groups are aware of the affiliation between PSE&G and PSEG Power. In periods of rising utility rates, those officials and advocacy groups may question or challenge costs and transactions incurred by PSE&G with PSEG Power, irrespective of any previous regulatory processes or approvals underlying those transactions. The occurrence of such challenges may subject PSEG Power to a level of scrutiny not faced by other unaffiliated competitors in those markets and could adversely affect retail rates received by PSE&G in an effort to offset any perceived benefit to PSEG Power from the affiliation.

PSE&G’s proposed investment projects or programs may not be fully approved by regulators and actual capital investment by PSE&G may be lower than planned, which would cause lower than anticipated rate base.

PSE&G is a regulated public utility that operates and invests in an electric T&D system and a gas distribution system as well as certain regulated clean energy investments, including solar and EE within New Jersey. PSE&G invests in capital projects to maintain and improve its existing T&D system and to address various public policy goals and meet customer expectations. Transmission projects are subject to a FERC-approved transmission expansion planning process while distribution and clean

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energy projects are subject to approval by the BPU. The costs of PSE&G’s transmission projects are subject to prudency challenge at FERC and PSE&G’s rates themselves may also be challenged at FERC. FERC has also proposed elimination of certain transmission rate incentives, including the incentive that PSE&G receives for being a transmission owner member of PJM and accepting the related risk of RTO membership.

We cannot be certain that any proposed project or program will be approved as requested or at all. If the projects or programs that PSE&G may file from time to time are only approved in part, or not at all, or if the approval fails to allow for the timely recovery of all of PSE&G’s costs, including a return of, or on, its investment, PSE&G will have a lower than anticipated rate base, thus causing its future earnings to be lower than anticipated. Further, the BPU could take positions to exclude or limit utility participation in certain areas, such as renewable generation, EE, EV infrastructure, or energy storage programs, renewable natural gas or hydrogen projects, which would limit our relationship with customers and narrow our future growth prospects.

We are subject to comprehensive federal regulation that affects, or may affect, our businesses.

We are subject to regulation by federal authorities. Such regulation affects almost every aspect of our businesses, including management and operations; the terms and rates of transmission services; investment strategies; the financing of our operations and the payment of dividends. Failure to comply with these regulations could have a material adverse impact on our ability to operate our business and could result in fines, penalties or sanctions.

Recovery of wholesale transmission rates—PSE&G’s wholesale transmission rates are regulated by FERC and are recovered through a FERC-approved formula rate. The revenue requirements are reset each year through this formula.

In 2021, FERC approved a settlement agreement effective August 1, 2021 that we reached with the BPU and the New Jersey Rate Counsel about the level of PSE&G’s base transmission ROE and other formula rate matters. The settlement reduced PSE&G’s base ROE from 11.18% to 9.9% and made changes to recovery of certain costs. The agreement provided that the settling parties will not seek changes to our transmission formula rate for three years.

In April 2021, FERC issued a supplemental notice of proposed rulemaking to eliminate the incentive for RTO membership for transmitting utilities that have already received the incentive for three or more years. PSE&G began receiving a 50 basis point adder for RTO membership in 2008. Elimination of the adder for RTO membership would reduce PSE&G’s annual Net Income and annual cash inflows by approximately $40 million.

Transmission Planning—FERC Order 1000 has generally opened transmission development to competition from independent developers, allowing such developers to compete with incumbent utilities for the construction and operation of transmission facilities in its service territory. While Order 1000 retains limited carve-outs for certain projects that will continue to default to incumbents for construction responsibility, including immediately needed reliability projects, upgrades to existing transmission facilities, and projects cost-allocated to a single transmission zone, increased competition for transmission projects could decrease the value of new investments that would be subject to recovery by PSE&G under its rate base, which could have a material adverse impact on our financial condition and results of operations. FERC is currently considering whether to modify Order 1000’s competition rules to further limit competition in an effort to encourage collaborative planning of large regional and interregional transmission projects. FERC is also examining whether additional oversight is needed to control transmission costs.

A significant input into PJM’s transmission planning process is its regional load forecast, which is adjusted on an annual basis. In 2023, PJM adjusted its load forecast in the PSEG zone to reflect New Jersey’s clean energy policies, including electrification requirements and projected EV penetration. Developing an accurate load forecast that reflects the clean energy targets of the state – and other states in PJM – is critical to ensure that transmission is planned and built where it is needed to maintain reliability.

NERC Compliance—NERC, at the direction of FERC, has implemented mandatory NERC Operations and Planning and Critical Infrastructure Protection standards to ensure the reliability of the North American Bulk Electric System, which includes electric transmission and generation systems, and to prevent major system blackouts. NERC Critical Infrastructure Protection standards establish cybersecurity and physical security protections for critical systems and facilities. We have been, and will continue to be, periodically audited by NERC for compliance with both Operations and Planning and Critical Infrastructure Protection standards and are subject to penalties for non-compliance with applicable NERC standards. NERC is conducting more frequent audits than was the case in the past and we must always be in a state of audit readiness. Failure to comply with applicable NERC standards could result in penalties or increased costs to bring such facilities into compliance. Such penalties and costs could materially adversely impact our business, results of operations and cash flows. Adverse audit findings and/or penalties for non-compliance also pose reputational risk to us.

MBR Authority and Other Regulatory Approvals—Under FERC regulations, public utilities that sell power at market rates must receive MBR authority before making power sales, and the majority of our businesses operate with such authority. Failure to maintain MBR authorization, or the effects of any severe mitigation measures that would be required if market power was

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evaluated differently in the future, could have a material adverse effect on our business, financial condition and results of operations. In December 2022, all of PSEG’s operating companies with MBR authority filed at FERC for acceptance of the companies’ updated triennial market power analysis. This filing remains pending at FERC.

Oversight by the CFTC relating to derivative transactions—The CFTC has regulatory oversight of the swap and futures markets and options, including energy trading, and licensed futures professionals such as brokers, clearing members and large traders. Changes to regulations or adoption of additional regulations by the CFTC, including any regulations relating to futures and other derivatives or margin for derivatives and increased investigations by the CFTC, could negatively impact PSEG Power’s ability to hedge its portfolio in an efficient, cost-effective manner by, among other things, potentially decreasing liquidity in the forward commodity and derivatives markets or limiting PSEG Power’s ability to utilize non-cash collateral for derivatives transactions.

We may also be required to obtain various other regulatory approvals to, among other things, buy or sell assets, engage in transactions between our public utility and our other subsidiaries, and, in some cases, enter into financing arrangements, issue securities and allow our subsidiaries to pay dividends. Failure to obtain these approvals on a timely basis could materially adversely affect our results of operations and cash flows.

The markets, PTC and/or ZEC program may not provide sufficient financial support for our New Jersey nuclear plants which could result in the retirement of all of these nuclear plants.

As further described in Item 7. MD&A—Executive Overview of 2023 and Future Outlook, in April 2019, PSEG Power’s Salem 1, Salem 2 and Hope Creek nuclear plants were awarded ZECs by the BPU through May 2022. In April 2021, these nuclear plants were awarded ZECs for the three-year period starting June 2022.

In August 2022, the IRA was signed into law expanding incentives promoting carbon-free generation. The enacted legislation established a PTC for electricity generation using nuclear energy which begins January 1, 2024 and continues 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 threshold are subject to annual inflation adjustments. The U.S. Treasury is expected to clarify the definition of gross receipts. The ZEC payment may be adjusted by the BPU to offset environmental or fuel diversity payments that a selected nuclear plant may receive from another source. Until additional guidance is issued by the U.S. Treasury, we are unable to fully determine the impacts of the PTC.

If the markets, PTC and/or the ZEC program do not provide sufficient financial support, or, in the case of the Salem nuclear plants, decisions by the EPA and state environmental regulators regarding the implementation of Section 316(b) of the CWA and related state regulations, or other factors, PSEG Power may take all necessary steps to cease to operate 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. Ceasing operations of these plants would result in a material adverse impact on PSEG’s results of operations.

We may be adversely affected by changes in energy regulatory policies, including energy and capacity market design rules and developments affecting transmission.

The energy industry continues to be regulated and the rules to which our businesses are subject are always at risk of being changed. Our business has been impacted by established rules that create locational capacity markets in PJM. Under these rules, generators located in constrained areas are paid more for their capacity so there is an incentive to locate in those areas where generation capacity is most needed. PJM’s capacity market design rules continue to evolve, including in response to efforts to integrate public policy initiatives into the wholesale markets, and recent extreme weather events in PJM. For a discussion of recent changes in energy regulatory policies that may affect our business and results of operations, see Item 1. Regulatory Issues—Federal Regulation.

Further, some of the market-based mechanisms in which we participate are at times the subject of review or discussion by some of the participants in the New Jersey and federal arenas. We can provide no assurance that these mechanisms will continue to exist in their current form, nor otherwise be modified.

In July 2021, the BPU issued a report on its investigation related to whether New Jersey can achieve its long-term clean energy and environmental objectives under the current resource adequacy procurement paradigm. The report found that participating in the regional market is the most efficient way for New Jersey to achieve its clean energy goals and therefore consideration of leaving the regional market is paused while market reforms are being considered at the regional and national level. In September 2022, the BPU issued a Progress Report expanding on the recommendations contained in the 2021 report. The Progress Report found that it is in New Jersey’s best interest to pursue a voluntary independent clean energy market and the BPU Staff sought the BPU’s authorization to evaluate various options that would serve as alternatives to the PJM capacity market or work in conjunction with it. The BPU is currently examining whether and how to implement a forward clean energy attributes market that could involve several states in PJM and work in tandem with PJM’s capacity and energy markets. We

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cannot predict whether the BPU will ultimately take any measures in the future that will have an impact on the capacity market or our generating stations.

Our ownership and operation of nuclear power plants involve regulatory risks as well as financial, environmental and health and safety risks.

We are exposed to risks related to the continued successful operation of our nuclear facilities and issues that may adversely affect the nuclear generation industry. In addition to the risk of retirement discussed below, risks associated with the operation of nuclear facilities include:

Storage and Disposal of Spent Nuclear Fuel—Federal law requires the United States Department of Energy (DOE) to provide for the permanent storage of spent nuclear fuel. The DOE has not yet begun accepting spent nuclear fuel. Until a federal site is available, we use on-site storage for spent nuclear fuel, which is reimbursed by the DOE. However, future capital expenditures may be required to increase spent fuel storage capacity at our nuclear facilities. Once a federal site is available, the DOE may impose fees to support a permanent repository. Further, the on-site storage for spent nuclear fuel may significantly increase our nuclear unit decommissioning costs.

Regulatory and Legal Risk—We may be required to substantially increase capital expenditures or operating or decommissioning costs at our nuclear facilities if there is a change in the Atomic Energy Act or the applicable regulations, trade controls or the environmental rules and regulations applicable to nuclear facilities; a modification, suspension or revocation of licenses issued by the NRC; the imposition of civil penalties for failure to comply with the Atomic Energy Act, related regulations, trade controls or the terms and conditions of the licenses for nuclear generating facilities; or the shutdown of one of our nuclear facilities. Any such event could have a material adverse effect on our financial condition or results of operations.

Operational Risk—Operations and equipment reliability at any of our nuclear facilities could degrade to the point where an affected unit needs to be shut down or operated at less than full capacity. If this were to happen, identifying and correcting the causes could require significant time and expense and a significant outage could result in reduced earnings as we would have less electric output to sell and would be required to deliver on our forward sale commitments.

In addition, if a unit cannot be operated through the end of its current estimated useful life, our results of operations could be adversely affected by increased depreciation rates, impairment charges and accelerated future decommissioning costs.

Nuclear Incident or Accident Risk—Accidents and other unforeseen problems have occurred at nuclear stations, both in the U.S. and elsewhere. The consequences of an accident can be severe and may include loss of life, significant property damage and/or a change in the regulatory climate. We have nuclear units at two sites. It is possible that an accident or other incident at a nuclear generating unit could adversely affect our ability to continue to operate unaffected units located at the same site, which would further affect our financial condition, results of operations and cash flows. An accident or incident at a nuclear unit not owned by us could lead to increased regulation, which could affect our ability to continue to economically operate our units. Any resulting financial impact from a nuclear accident may exceed our resources, including insurance coverages. Further, as a licensed nuclear operator subject to the Price-Anderson Act and a member of a nuclear industry mutual insurance company, PSEG Power is subject to potential retroactive assessments as a result of an industry nuclear incident or retrospective premiums due to adverse industry loss experience and such assessments may be material.

In the event of non-compliance with applicable legislation, regulation and licenses, the NRC may increase oversight, impose fines, and/or shut down a unit, depending on its assessment of the severity of the non-compliance. If a serious nuclear incident were to occur, our business, reputation, financial condition and results of operations could be materially adversely affected. In each case, the amount and types of insurance available to cover losses that might arise in connection with the operation of our nuclear fleet are limited and may be insufficient to cover any costs we may incur.

Decommissioning—NRC regulations require that licensees of nuclear generating facilities demonstrate reasonable assurance that funds will be available to decommission a nuclear facility at the end of its useful life. PSEG Nuclear has established an NDT Fund to satisfy these obligations. However, forecasting trust fund investment earnings and costs to decommission nuclear generating stations requires significant judgment, and actual results could differ significantly from current estimates. If we determine that it is necessary to retire one of our nuclear generating stations before the end of its useful life, there is a risk that it will no longer meet the NRC minimum funding requirements due to the earlier commencement of decommissioning activities and a shorter time period over which the NDT investments could appreciate in value. A shortfall could require PSEG to post parental guarantees or make additional cash contributions to ensure that the NDT Fund continues to satisfy the NRC minimum funding requirements. As a result, our financial position or cash flows could be significantly adversely affected.

Third-Party Operation of Peach Bottom Plants—While we have a 50% ownership interest in the Peach Bottom nuclear generation plants, these plants are operated by a third party and, therefore, we have limited control over the operational and other risks associated with these plants.

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We are subject to numerous federal, state and local environmental laws and regulations that may significantly limit or affect our businesses, adversely impact our business plans or expose us to significant environmental fines and liabilities.

We are subject to extensive federal, state and local environmental laws and regulations regarding air quality, water quality, site remediation, land use, waste disposal, climate change impact, natural resource damages and other matters. These laws and regulations affect how we conduct our operations and make capital expenditures. Over the past several years, there have been various changes to existing environmental laws and regulations and this trend may continue. Changes in these laws, or violations of laws, could result in significant increases in our compliance costs, capital expenditures to bring facilities into compliance, operating costs for remediation and clean-up actions, civil penalties or damages from actions brought by third parties for alleged health or property damages. Any such increase in our costs could have a material impact on our financial condition, results of operations and cash flows and could require further economic review to determine whether to continue operations or decommission an affected facility. We may also be unable to successfully recover certain of these cost increases through our existing regulatory rate structures, in the case of PSE&G, or our contracts with our customers, in the case of PSEG Power.

Actions by state and federal government agencies could also result in reduced reliance on natural gas and could potentially result in stranding natural gas assets owned and operated by PSE&G, which could materially adversely affect our business, financial condition and results of operations.

PSE&G recovers certain remediation and legal costs associated with its manufactured gas plant sites through Remediation Adjustment Charge (RAC) filings with the BPU. Continued future recoveries through the RAC are not guaranteed. Any failure to make future recoveries could materially impact our financial condition.

In addition, PSEG Power retained ownership of certain liabilities excluded from the sale of its fossil generation portfolio. These primarily relate to obligations under environmental regulations, including remediation obligations under the New Jersey Industrial Site Recovery Act and the Connecticut Transfer Act. It will require multiple years and comprehensive environmental sampling to understand the extent of and to carry out the required remediation. At this stage of the remediation process, the full remediation costs are not estimable, but given the number and operating history of the facilities in the portfolio, the full remediation costs will likely be material in the aggregate. The costs could potentially include costs for, among other things, excavating soil, implementation of institutional controls, and the construction, operation and maintenance of engineering controls.

Environmental laws and regulations have generally become more stringent over time, and this trend is likely to continue. For further discussion of environmental laws and regulations impacting our business, results of operations and financial condition, including the impact of federal and state laws and regulations relating to remediation of environmental contamination, see Item 8. Note 13. Commitments and Contingent Liabilities.

We may not receive necessary licenses, permits and siting approvals in a timely manner or at all, which could adversely impact our business and results of operations.

We must periodically apply for licenses and permits from various regulatory authorities, including environmental regulatory authorities, and siting/permitting approvals for our transmission investments, and abide by their respective orders. Delay in obtaining, or failure to obtain and maintain, any permits or approvals, including environmental permits or approvals, or delay in or failure to satisfy any applicable regulatory requirements, could:

•prevent construction of new facilities,

•limit or prevent continued operation of existing facilities,

•limit or prevent the sale of energy from these facilities, or

•result in significant additional costs,

each of which could materially affect our business, financial condition, results of operations and cash flows. In addition, the process of obtaining licenses and permits from regulatory authorities may be delayed or defeated by concerted community opposition and such delay or defeat could have a material effect on our business.

Changes in tax laws and regulations may adversely affect our financial condition, results of operations and cash flows.

The enactment of additional federal or state tax legislation and clarification of previously enacted tax laws, including anticipated U.S. Treasury guidance relating to the 15% corporate alternative minimum tax and energy tax credit provisions, could have a material impact on our effective tax rate and cash tax position.

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ITEM 1B. UNRESOLVED STAFF COMMENTS

PSEG and PSE&G

None.

ITEM 1C. CYBERSECURITY

In an effort to reduce the likelihood and severity of cybersecurity incidents, we have established a comprehensive cybersecurity program designed to protect and preserve the confidentiality, integrity and availability of our technology systems and our business operations more broadly. For a discussion of the risks associated with cybersecurity threats, see Item 1A. Risk Factors.

Risk Management and Strategy

Our processes for assessing, identifying, and managing material risks from cybersecurity threats include the following:

•Ongoing Assessment—The Cybersecurity Risk and Compliance department, led by the Managing Director, Chief Information Security Officer (CISO), and reporting to the SVP, Chief Information and Digital Officer (CIDO) is staffed with cyber professionals tasked with the day-to-day responsibility of assessing material risks from cybersecurity threats. In addition, the Cyber Security Council, comprised of senior management, is kept apprised of the state of PSEG’s cybersecurity program, including any emerging risks, and provides guidance on the strategic directions of the program.

•Engagement of Third Parties—We engage third parties, such as security service providers, risk management firms and external legal counsels to assess material risks from cybersecurity threats and report on our internal incident response preparedness and cyber posture, support incident response, conduct tabletop exercises, and comply with applicable laws and regulations. We also carry cybersecurity insurance that provides certain protection against losses from a cybersecurity incident. Regulatory agencies, including but not limited to the NRC and Transportation Security Administration, as well as NERC, inspect applicable components of our cybersecurity program.

•Third-Party Service Provider Management—We maintain processes to oversee and identify risks from cybersecurity threats associated with our use of third-party service providers. This includes a risk-based vendor management program, which incorporates robust security contractual provisions, vendor security assessments and, if appropriate, periodic audits.

•Technical Safeguards—We manage controls to protect our network perimeter, internal IT and Operational Technology (OT) environments, such as internal and external firewalls, network intrusion detection and prevention, penetration testing, vulnerability assessments, threat intelligence, anti-malware and access controls.

•Training and Awareness—We provide mandatory annual cybersecurity training for all personnel with network access, as well as additional education for personnel with access to industrial control systems or customer information systems; and conduct phishing exercises with progressive consequences for failures. Employees also receive periodic cybersecurity awareness messages and each October, in recognition of Cybersecurity Awareness Month, are invited to presentations throughout the month from internal and external cyber experts covering diverse cyber topics. These efforts better enable all employees to identify potential cybersecurity risks and escalate them appropriately.

•Incident Response Plans—We maintain and periodically update a cyber incident response plan that addresses the life cycle of a cybersecurity incident from a technical perspective (i.e., detection, response, and recovery), as well as a data breach response plan (with a focus on external communication/disclosure and legal compliance); and conduct regular tabletop exercises to test plan effectiveness (both internally and through external exercises).

•Mobile Security—We maintain controls to prevent loss of data through mobile device channels.

•Physical Security—We also maintain physical security measures to protect our OT systems, consistent with a defense in-depth and risk-tiered approach. Such physical security measures may include access control systems, video surveillance, around-the-clock command center monitoring, and physical barriers (such as fencing, walls, and bollards). Additional features of PSEG’s physical security program include threat intelligence, insider threat mitigation, background checks, a threat level advisory system, a business interruption management model, and active coordination with federal, state, and local law enforcement officials. See Item 1. Business. Regulatory Issues—Federal Regulation for a discussion of Critical Infrastructure Protection standards that the NERC has promulgated that mitigate risk associated with both cybersecurity and physical security of PSEG’s critical facilities.

These processes are integral to our overall risk management system or processes and inform the identification and assessment

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of risks and mitigations through our Enterprise Risk Management (ERM) program. The ERM team, led by the SVP – Audit, Enterprise, Risk and Compliance (AERC) considers cybersecurity risks alongside other PSEG risks, and facilitates discussion with PSEG subject matter experts to identify cybersecurity risks, evaluate their potential severity and likelihood, identify mitigations, including those identified above, and assess the impact of those mitigations on residual risk. In addition, PSEG maintains a Risk Management Committee (RMC), responsible for assessing exposure to and determining PSEG's overall risk management strategy, including with respect to cybersecurity. The RMC, supported by the ERM function, is chaired by the SVP – AERC and consists of members of senior management including the CIDO and six other of the CEO’s direct reports. In discharging its responsibilities related to cybersecurity threats, the RMC has received presentations from the CISO. To date, there has been no material impact or reasonably likely material impact on our business strategy, results of operations or financial condition from these attacks or other cybersecurity incidents, including as a result of prior cybersecurity incidents.

Governance

–PSEG Board of Directors (Board) Oversight of Risks from Cybersecurity Threats:

•PSEG Board —The PSEG Board has ultimate responsibility for the oversight of risk management at PSEG, overseeing PSEG’s risk management program and reviewing the most significant risks facing PSEG, including cybersecurity risks. The Governance, Nominating and Sustainability Committee of the PSEG Board reviews key enterprise risks, including cybersecurity risks, and recommends to the Board the mapping of each risk to an appropriate committee or the full Board, in accordance with the allocation of risk categories reflected in the charter of each committee. Through this process, cybersecurity risk is mapped primarily to the Board’s Industrial Operations Committee (IOC), and also the Audit Committee. In providing oversight of risks from cybersecurity threats, the Board is informed of cybersecurity incidents as appropriate, by way of updates from Senior Management, pursuant to PSEG’s Cybersecurity Event Escalation and Incident Response Practice, as administered by the CISO.

•IOC—At the PSEG Board level, the IOC holds the primary responsibility, as enumerated in its charter, of overseeing PSEG’s cybersecurity program and assessing overall compliance through active, independent and critical oversight. The IOC is informed about cybersecurity risks by the CIDO and/or the CISO, during the IOC’s four regularly scheduled meetings a year, which each include cybersecurity as a standing agenda item. Cybersecurity updates to the IOC include discussions on OT and IT cyber risk, a cybersecurity update from the CISO and/or CIDO, and review of a corporate cybersecurity scorecard and other performance indicators. The CIDO and CISO are regular attendees at IOC meetings. In addition, the IOC meets with the CISO in executive session at each meeting with no other members of management present, and has also met with the CIDO, to whom the CISO directly reports, in executive session with no other members of management present. To ensure the full Board is kept informed about the cybersecurity risks discussed at the IOC meetings, the cybersecurity materials provided to the IOC are available for full viewing by all members of the Board, members of the Board who are not IOC members have a courtesy invitation to each IOC meeting, and the Chair of the IOC provides a summary of IOC meetings to the full Board, typically the day after the meeting takes place.

•Audit Committee—The Audit Committee has the charter responsibility of overseeing cybersecurity risks related to financial reporting and internal controls. The Audit Committee receives a cybersecurity update twice a year from the CIDO, either with the full Board or the IOC in attendance. Audit Committee members have a courtesy invitation to all IOC meetings, have full access to IOC meeting materials, and receive the summary of IOC meetings from the IOC Chair noted above.

•Governance, Nominating and Sustainability Committee and Audit Committee—These committees are briefed at least annually on enterprise-level risks and emerging risks, including those related to cybersecurity, and receive regular updates on PSEG RMC activities, including those related to cybersecurity.

•Board of Directors, IOC, and Audit Committee—In providing oversight of risks from cybersecurity threats, the Board, IOC and Audit Committee are informed of cybersecurity risks by way of frequent reports on such topics as personnel and resources to monitor and address cybersecurity threats, technological advances in cybersecurity protection, rapidly evolving cybersecurity threats that may affect us and our industry, cybersecurity incident response and applicable cybersecurity laws, regulations and standards, as well as collaboration mechanisms with intelligence and enforcement agencies and industry groups to assure timely threat awareness and response coordination. In addition, risks associated with cybersecurity incidents, or potential incidents, are escalated by senior management promptly to the Board outside of regularly scheduled meetings, if appropriate.

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–Management’s Role in Assessing and Managing Material Cybersecurity Risks:

The assessment and management of material risks from cyber threats is managed by the CIDO, CISO and Cybersecurity Council, as further described below.

•CIDO—The CIDO has had the overall responsibility for PSEG’s cybersecurity since September 2022, including the assessment and management of materials risks to PSEG from cybersecurity threats. The CIDO has served in that position since August 2020 and is a direct report of the CEO. The CIDO has over 25 years of energy experience inclusive of leading technology compliance with cybersecurity regulations for nuclear, transmission, gas and corporate assets. Our CIDO’s experience includes leading the secure technology design, development, and deployment strategy for grid modernization efforts, including digital customer engagement platforms, advanced metering, enterprise asset management and distribution automation functionality.

As noted above, the CIDO provides cybersecurity updates to the Board or its Committees twice per year, regularly attends and provides updates with the CISO to the IOC, and has met with the IOC, without other members of management present, during the IOC executive sessions.

The CIDO remains informed about the monitoring, prevention, detection, mitigation, and remediation of cybersecurity incidents through the CISO and other members of the cybersecurity, risk and compliance team, as appropriate, who are tasked with these responsibilities on a day-to-day basis.

•CISO—The CISO has day-to-day responsibility for PSEG’s cybersecurity, including the assessment and management of material risks to PSEG from cybersecurity threats, and leads the cybersecurity, risk and compliance team. The CISO has served in this role since September 2018. Our CISO has over 20 years of experience in IT security management and served as the director of information security and chief security architect in the insurance sector prior to joining PSEG. Our CISO has a bachelor’s degree in electrical engineering and holds multiple security certifications, including Certificate of Cloud Security Knowledge, Certified Information Systems Security Professional, Certified Information Systems Auditor, Information Systems Security Architecture Professional, and National Institute of Standards and Technology Cyber Security Professional Practitioner.

As noted above, the CISO provides cybersecurity updates during the four regularly scheduled IOC meetings and meets with the IOC, without other members of management present, during each meeting’s executive session. The CISO remains informed about the monitoring, prevention, detection, mitigation, and remediation of cybersecurity incidents through the members of the CISO’s cybersecurity, risk and compliance team, who are tasked with these responsibilities on a day-to-day basis.

•Cybersecurity Council—The Cybersecurity Council, chaired by the CISO, ensures that senior management, and ultimately, the Board, are given the information required to exercise proper oversight over cybersecurity risks and that escalation procedures are followed. The Cybersecurity Council meets at least six times annually to receive reports on the state of PSEG’s cybersecurity program, provide guidance on the strategic direction of the program, discuss emerging cybersecurity issues, and review the cybersecurity scorecard to measure performance of key risk indicators. The Cybersecurity Council receives presentations from the CISO, members of the Cybersecurity Risk and Compliance Team cybersecurity managing counsel, and external cybersecurity experts, and participates in tabletop exercises led by external consultants. In addition to the CISO, the Cybersecurity Council members include the: (i) CIDO; (ii) EVP and General Counsel; (iii) EVP and CFO; (iv) President and COO of PSE&G; (v) President of PSEG Nuclear and Chief Nuclear Officer; (vi) SVP – Corporate Citizenship; (vii) SVP – Chief Human Resources and Diversity Officer; (viii) VP of Corporate Security and Properties; (ix) SVP – AERC; (x) Project Executive Advisor; and (xi) Vice President and Controller. PSEG’s Managing Counsel – Cybersecurity serves as counsel to the Cybersecurity Council.

In providing oversight of risks from cybersecurity threats, Senior Management is informed of cybersecurity risks by way of updates shared during Cybersecurity Council meetings, as well as through notifications or updates by the CISO, pursuant to PSEG’s Cybersecurity Event Escalation and Incident Response Practice.

For a discussion of regulatory requirements relating to cybersecurity matters, see Item 1. Business—Regulatory Issues.

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ITEM 2. PROPERTIES

All of our owned physical property is held by our subsidiaries. We believe that we and our subsidiaries maintain adequate insurance coverage against loss or damage to plants and properties, subject to certain exceptions and deductibles, to the extent such property is usually insured and insurance is available at a reasonable cost. For a discussion of nuclear insurance, see Item 8. Note 13. Commitments and Contingent Liabilities.

PSE&G

Primarily all of PSE&G’s property is located in New Jersey and PSE&G’s First and Refunding Mortgage, which secures the bonds issued thereunder, constitutes a direct first mortgage lien on substantially all of PSE&G’s property. PSE&G’s electric lines and gas mains are located over or under public highways, streets, alleys or lands, except where they are located over or under property owned by PSE&G or occupied by it under easements or other rights. PSE&G deems these easements and other rights to be adequate for the purposes for which they are being used.

Electric Property and Facilities

As of December 31, 2023, PSE&G’s electric T&D system included approximately 25,000 circuit miles, and 866,000 poles, of which 64% are jointly-owned. In addition, PSE&G owns and operates 56 switching stations with an aggregate installed capacity of 39,953 megavolt-amperes (MVA) and 235 substations with an aggregate installed capacity of 10,382 MVA. Four of those substations, having an aggregate installed capacity of 109 MVA are operated on leased property. In addition, PSE&G owns four electric distribution headquarters and five electric sub-headquarters.

Gas Property and Facilities

As of December 31, 2023, PSE&G’s gas system included approximately 18,000 miles of gas mains, 12 gas distribution headquarters, two sub-headquarters, and one meter shop serving all of its gas territory in New Jersey. In addition, PSE&G operates 56 natural gas metering and regulating stations, of which 26 are located on land owned by customers or natural gas pipeline suppliers and are operated under lease, easement or other similar arrangement. In some instances, the pipeline companies own portions of the metering and regulating facilities. PSE&G also owns one liquefied natural gas and three liquid petroleum air gas peaking facilities. The daily gas capacity of these peaking facilities (the maximum daily gas delivery available during the three peak winter months) is approximately 2.9 million therms in the aggregate.

Solar

As of December 31, 2023, PSE&G owned 158 MW dc of installed PV solar capacity throughout New Jersey.

PSEG Power

Generation Facilities

As of December 31, 2023, PSEG Power’s share of installed nuclear generating capacity is shown in the following

table:



Name	Location	Total Capacity (MW)	% Owned	Owned Capacity (MW)
Nuclear:
Hope Creek	NJ	1,174	100%	1,174
Salem 1 & 2	NJ	2,287	57%	1,312
Peach Bottom 2 & 3 (A)	PA	2,549	50%	1,275
Total Nuclear		6,010		3,761

(A)Operated by Constellation Energy Generation, LLC.

ITEM 3. LEGAL PROCEEDINGS

We are party to various lawsuits and environmental and regulatory matters, including in the ordinary course of business. For information regarding material legal proceedings, see Item 1. Business—Regulatory Issues and Environmental Matters and Item 8. Note 13. Commitments and Contingent Liabilities.

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ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Our common stock is listed on the New York Stock Exchange, Inc. under the trading symbol “PEG.” As of February 16, 2024, there were 47,943 registered holders.

The following graph shows a comparison of the five-year cumulative return assuming $100 invested on December 31, 2018 in our common stock and the subsequent reinvestment of quarterly dividends, the S&P Composite Stock Price Index, the Dow Jones Utilities Index and the S&P Electric Utilities Index.



	2018		2019		2020		2021		2022		2023
PSEG	$	100.00	$	117.08	$	119.88	$	141.85	$	134.62	$	139.49
S&P 500	$	100.00	$	131.47	$	155.65	$	200.29	$	163.98	$	207.04
DJ Utilities	$	100.00	$	127.30	$	129.44	$	152.04	$	155.15	$	146.94
S&P Utilities	$	100.00	$	126.35	$	127.01	$	149.46	$	151.79	$	141.05

On February 13, 2024, our Board of Directors approved a $0.60 per share common stock dividend for the first quarter of 2024. This reflects an indicative annual dividend rate of $2.40 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.

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The following table indicates the securities authorized for issuance under equity compensation plans as of December 31, 2023:



Plan Category	Number of Securities to be Issued upon Exercise of Outstanding Options, Warrants and Rights (a)	Weighted-Average Exercise Price of Outstanding Options, Warrants and Rights (b)		Number of Securities Remaining Available for Future Issuance under Equity Compensation Plans (excluding securities reflected in column (a)) (c)
Equity Compensation Plans Approved by Security Holders	—	$	—	8,162,450
Equity Compensation Plans Not Approved by Security Holders	—	—		—
Total	—	$	—	8,162,450

The number of shares available for future issuance includes amounts remaining under our 2021 Long-Term Incentive Plan (2021 LTIP) and 2021 Equity Compensation Plan for Outside Directors and the Employee Stock Purchase Plan and reflect a reduction for non-vested restricted stock units and performance share units (PSUs) (assumed at target payout). The number of shares available for future issuance may be increased or decreased depending on actual payouts for the PSUs based on achievement of targets and is increased by the number of shares that are forfeited, canceled or otherwise terminated without the issuance of shares. For additional discussion of specific plans concerning equity-based compensation, see Item 8. Note 18. Stock Based Compensation.

PSE&G

We own all of the common stock of PSE&G. For additional information regarding PSE&G’s ability to continue to pay dividends, see Item 7. MD&A—Liquidity and Capital Resources.

ITEM 6. [RESERVED]

ITEM 7. 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). Information contained herein relating to any individual company is filed by such company on its own behalf.

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), the Federal Energy Regulatory Commission (FERC), and other federal and New Jersey state regulators. PSE&G also invests in regulated solar generation projects and energy efficiency (EE) and related programs in New Jersey, which are regulated by the BPU, and

•PSEG Power—which is an energy supply company that integrates the operations of its merchant nuclear generating assets with its fuel supply functions through competitive energy sales via its principal direct wholly owned subsidiaries. PSEG Power’s subsidiaries are subject to regulation by FERC, the Nuclear Regulatory Commission (NRC) 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, which are: PSEG Long Island LLC (PSEG LI), which operates the Long Island Power Authority’s (LIPA) transmission and distribution (T&D) system under an Operations Services Agreement (OSA); PSEG Energy Holdings L.L.C. (Energy Holdings), which primarily holds legacy lease investments and competitively bid, FERC regulated transmission; and PSEG Services Corporation (Services), which provides certain management, administrative and general services to PSEG and its subsidiaries at cost.

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Our business discussion in Item 1. Business 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 Item 1A. Risk Factors provides information about factors that could have a material adverse impact on our businesses. The following discussion provides an overview of the significant events and business developments that have occurred during 2023 and key factors that we expect may drive our future performance. This discussion refers to the Consolidated Financial Statements (Statements) and the related Notes to the Consolidated Financial Statements (Notes). This discussion should be read in conjunction with such Statements and Notes.

EXECUTIVE OVERVIEW OF 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 focuses on achieving growth by allocating capital primarily toward regulated investments in an effort to continue to improve the sustainability and predictability of our business. We are focused on investing to modernize our energy infrastructure, improve reliability and resilience, increase EE and deliver cleaner energy to meet customer expectations and be well aligned with public policy 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. In addition, the passage of the Inflation Reduction Act of 2022 (IRA) established a production tax credit (PTC) for existing nuclear facilities from 2024 through 2032. The PTC is expected to provide downside price protection for our nuclear generation fleet as the tax credit value is directly linked to a nuclear facility’s gross receipts.

For the years 2024-2028, our regulated capital investment program is estimated to be in a range of $18 billion to $21 billion. We expect these capital investments to result in a compound annual growth rate in our regulated rate base in a range of 6% to 7.5% from year-end 2023 to year-end 2028. The regulated capital investments represent the majority of PSEG’s total capital investment program of $19 billion to $22.5 billion. The low end of the 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 incremental investments, particularly for an expansion of our current EE programs as well as other clean energy and infrastructure investments.

PSE&G

At PSE&G, our focus is on investing capital in T&D infrastructure and clean energy programs to enhance the reliability and resiliency of our T&D system, meet customer expectations and support public policy objectives.

During 2023, the BPU approved a $280 million nine-month extension of our CEF-EE program through June 2024 and a two-year extension of our current GSMP program to replace at least 400 miles of cast iron and unprotected steel mains and services in our gas system. The GSMP program extension provides for main replacement through December 2025 plus trailing services replacement and paving costs into 2026 and totals approximately $900 million of investment. Of the $900 million, $750 million is recovered through three periodic rate updates with the balance recovered through a future distribution base rate case.

Our broader GSMP III, which also included projects to introduce renewable natural gas and hydrogen blending into our existing distribution system is being held in abeyance, with negotiations reinitiated by January 2025 with the intent of beginning the work in January 2026. A remaining component of our CEF-Electric Vehicle (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 2024. In September 2022, the BPU released a draft Storage Incentive Program proposal and is currently undertaking a stakeholder process to determine the details of the program. In the meantime, our CEF-Energy Storage (ES) program is being held in abeyance.

In November 2023, we filed for a second extension of our CEF-EE program, which would cover a commitment period of six months from July 2024 through December 2024 for approximately $300 million. In December 2023, we filed for our CEF-EE II program, which proposed a $3.1 billion investment for a second program cycle covering commitments from January 2025 through June 2027, with investments being made over a six-year period. This EE filing is a significant increase from our prior filings, driven by an increase in the savings targets required under the BPU Energy Efficiency Framework and higher costs to achieve those targeted savings. The filing also includes demand response programs and building decarbonization programs. The CEF-EE extension filing is expected to be resolved in the first half of 2024 and the EE II filing is expected to be resolved in the second half of 2024.

Pursuant to our GSMP II and Energy Strong II programs, we filed a distribution base rate case as required by the BPU in December 2023. Among other things, the distribution base rate case will seek to recover capital expenditures associated with our infrastructure investment programs that are not already in rates, as well as the Advanced Metering Infrastructure (AMI) and EV programs, other investments that are not recovered through periodic rate roll-ins, and several other cost and return factors.

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The filing proposes an overall revenue increase of 9% with a 12% increase for the combined typical residential electric and gas customer. We expect to conclude the distribution base rate case later in 2024.

PSEG Power

At PSEG Power, we seek to produce low-cost, reliable and resilient electricity by efficiently operating our nuclear generation assets, mitigate earnings volatility through the PTC mechanism and hedging, and support public policies that preserve these existing carbon-free base load nuclear generating plants. During 2023, our nuclear units generated approximately 32 terawatt hours and operated at a capacity factor of approximately 93%. As of the end of 2023, PSEG Power has hedged approximately 90% to 95% of its expected generation output for 2024. Beginning in 2024, our hedging strategy will incorporate an estimated range of risk reduction impacts from the PTCs on our nuclear generation portfolio. This is expected to result in changes to our current approach given PTC guidance uncertainty, and potential incremental changes upon final U.S. Treasury guidance.

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, fuel combustion at PSEG facilities, methane leaks, vehicle fleet emissions, sulfur hexafluoride emissions, and refrigerant leaks. Scope 2 emissions include purchased electric and steam energy for our PSEG facilities and emissions associated with line losses. Consistent with our commitment to the United Nations-backed Race to Zero campaign, we had submitted proposed targets encompassing Scopes 1, 2 and 3 emissions to the Science-Based Targets initiative (SBTi). SBTi recently informed us that they have rejected our submittal because, while our Scope 1 and 2 and Scope 3 electric targets meet requirements to proceed to the validation process, our Scope 3 natural gas target aligns with a Well Below 2C temperature scenario, rather than a more ambitious 1.5C scenario.

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 and CEF-EE II programs are intended to support New Jersey’s Energy Master Plan and recent Gubernatorial Executive Orders through programs designed to help customers use energy more efficiently, reduce GHG emissions, support the expansion of the EV infrastructure in New Jersey, 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. As mentioned above, the BPU approved a two-year extension of GSMP in October 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 baseline 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.

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 PTC established by the IRA, and capacity market reform at PJM 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.

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Competitively Bid, FERC Regulated Transmission Projects

PSEG continues to evaluate investment opportunities in regulated transmission beyond PSE&G. In December 2023, PJM awarded a subsidiary of Energy Holdings an approximately $424 million project to address increasing load and reliability issues in Maryland as part of its 2022 Window 3 competitive solicitation. The project has an expected in-service date of 2027.

We also continue to evaluate regulated transmission opportunities to support offshore wind development in the New Jersey area. 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. 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.

In November 2023, the BPU issued an order directing its staff to conduct a solicitation for “pre-build infrastructure” to support landing and routing of underground transmission cables of future offshore wind projects. PSEG is evaluating this opportunity and may submit a bid or bids into the solicitation.

Financial Results

The financial results for PSEG, PSE&G and PSEG Power & Other for the years ended December 31, 2023 and 2022 are presented as follows:



	Years Ended December 31,
	2023		2022
	Millions, except per share data
PSE&G	$	1,515	$	1,565
PSEG Power & Other	1,048		(534)
PSEG Net Income	$	2,563	$	1,031

PSEG Net Income Per Share (Diluted)	$	5.13	$	2.06

For a detailed discussion of our financial results, see Results of Operations.

Regulatory, Legislative and Other Developments

We closely monitor and engage with stakeholders on significant regulatory and legislative developments.

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 proposal. If the adder was eliminated, it would reduce PSE&G’s annual Net Income and annual cash inflows by approximately $40 million.

New Jersey Stakeholder Proceedings

In February 2023, the governor of New Jersey issued executive orders (EOs) that establish or accelerate previously established 2050 targets for clean-sourced energy, building decarbonization, and EV adoption goals, with new target dates of 2030 or 2035, as applicable. The EOs direct the BPU and other state agencies to collaborate with stakeholders to develop plans to reach the targets and the BPU has convened a stakeholder proceeding to develop a plan for gas distribution utilities to reach the target of 50% natural gas emissions reductions over 2006 levels by 2030. We are unable to predict the outcomes of this proceeding, but it could have a material impact on our business, results of operations and cash flows.

Environmental Regulation

We are subject to liability under environmental laws for the costs and penalties of remediating 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 and state agencies to have discharged substantial contamination into the Passaic River/Newark Bay Complex in violation of various statutes. 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.

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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 8. Note 13. Commitments and Contingent Liabilities.

Nuclear

In April 2021, PSEG Power’s Salem 1, Salem 2 and Hope Creek nuclear plants were awarded zero emission certificates (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 $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 January 1, 2024 and continue 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 threshold are subject to annual inflation adjustments. The establishment of the PTC impacted PSEG Power’s decision not to apply for the next ZEC three-year eligibility period starting June 2025. We continue to analyze the impact of the IRA on our nuclear units, and will analyze any future guidance from the U.S. Treasury to assess any impact of PTCs on expected ZEC payments and/or any future ZEC application periods.

Pension and Interest Rate Matters

In February 2023, PSE&G received 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 ratemaking purposes. This order mitigates some of the volatility in earnings and customer rates related to our pension trust performance and became effective for calendar year 2023 and forward.

In July 2023, PSEG and Fiduciary Counselors Inc., as independent fiduciary of the Pension Plan I and Pension Plan II (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 group annuity contract that would transfer to the Insurer approximately $1 billion of the Plans’ defined benefit pension obligations and associated Plan assets related to certain pension benefits covering approximately 2,000 retirees from PSEG Power & Other. In August 2023, assets were transferred to the Insurer and the transaction was closed, which reduces future volatility due to lowering our pension assets and liabilities. See Item 8. Note 12. Pension, Other Postretirement Benefits (OPEB) and Savings Plans for additional information.

Federal Reserve policy to reduce inflation has resulted in a higher interest rate environment which may persist as the Federal Reserve continues to assess the economic outlook. If it persists, higher interest rates on borrowings will contribute to higher interest expense on variable-rate debt and long-term rates on future financing plans. As of December 31, 2023, PSEG had entered into floating-to-fixed interest rate swaps totaling $1.4 billion in order to reduce the volatility in interest expense related to $900 million of a $1.25 billion variable rate term loan at PSEG Power due March 2025 and PSEG’s $500 million variable rate term loan due April 2024. PSE&G’s interest rate risk is moderated due to annual transmission rate filings and distribution recoveries through base rate filings and clause-based investment programs.

Tax Legislation

Future federal and state tax legislation and clarification of enacted legislation could have a material impact on our effective tax rate and cash tax position.

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 T&D property. The impact, if any, this may have on PSEG and PSE&G’s financial statements has not yet been determined.

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. The U.S. Treasury has issued proposed regulations and several Notices pertaining to the CAMT and the prevailing wage and transferability rules of energy tax credits. 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 PSE&G’s results of operations, financial condition and cash flows, which could be material.

Future Outlook

Our future success will depend on our ability to continue to maintain strong operational and financial performance, address regulatory and legislative developments that impact our business and respond to the issues and challenges described below. In order to do this, we will continue to:

•seek approval of and execute on our utility capital investment program to modernize our infrastructure, 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,

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•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 the risks and opportunities in federal and state clean energy policies,

•advocate for appropriate regulatory guidance on the federal nuclear PTC to ensure long-term support for New Jersey’s largest carbon-free generation resource, and adapt our hedging program accordingly,

•engage constructively with our multiple stakeholders, including regulators, government officials, customers, employees, investors, suppliers and the communities in which we do business, and

•deliver on our human capital management strategy to attract, develop and retain a diverse, high-performing workforce.

In addition to the risks described elsewhere in this Form 10-K for 2023 and beyond, the key issues and 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, tax regulations, design of energy and capacity markets, and environmental regulation, as well as with respect to the outcome of any legal, regulatory or other proceedings,

•performance of the financial markets, including the impact on our pension and interest rates on our future financing plans,

•continuing to manage costs and maintain affordable customer rates in an inflationary environment, which could impact 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 access to our environment, and the increasing frequency and magnitude of physical attacks on electric and gas infrastructure,

•future changes in federal and state tax laws or any other associated tax guidance, and

•the impact of changes in demand, natural gas and electricity prices, and expanded efforts to decarbonize several sectors of the economy.

We continually assess a broad range of strategic options to maximize long-term shareholder value and address the interests of our 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 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 system to meet the growing needs and increasingly higher expectations of customers, and clean energy investments such as CEF-EE, CEF-EV, CEF-ES and solar,

•continued operation of our nuclear generation facilities that are expected to be supported through the PTC through 2032 and can enable certain investments to increase the capacity of the units as well as potential license extensions,

•investments in competitive, regulated transmission investments through PJM processes and BPU solicitations that provide revenue predictability and reasonable risk-adjusted returns, and

•acquisitions, dispositions, development and other transactions involving our common stock, assets or businesses that could provide value to customers and 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



	Years Ended December 31,
	2023		2022		2021
Earnings (Losses)	Millions, except per share data
PSE&G	$	1,515	$	1,565	$	1,446
PSEG Power & Other (A)(B)	1,048		(534)		(2,094)
PSEG Net Income (Loss)	$	2,563	$	1,031	$	(648)

PSEG Net Income (Loss) Per Share (Diluted)	$	5.13	$	2.06	$	(1.29)

(A)PSEG Power & Other results in 2023 include a $239 million after-tax pension charge due to the settlement of a portion of the qualified pension plans. PSEG Power & Other results in 2022 include after-tax impairments of $92 million related to certain Energy Holdings investments and additional adjustments related to the sale of PSEG Power’s fossil generation assets. PSEG Power & Other results in 2021 include an after-tax impairment loss and other associated charges, including debt extinguishment costs of $2,158 million related to the sale of PSEG Power’s fossil generation assets. See Item 8. Note 3. Asset Dispositions and Impairments for additional information.

(B)Other includes after-tax activities at the parent company, PSEG LI and Energy Holdings as well as intercompany eliminations.

PSEG Power’s results above include the Nuclear Decommissioning Trust (NDT) Fund 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 (Loss) attributable to changes related to the NDT Fund and MTM are shown in the following table:



	Years Ended December 31,
	2023		2022		2021
	Millions, after tax
NDT Fund and Related Activity (A) (B)	$	109	$	(174)	$	108
Non-Trading MTM Gains (Losses) (C)	$	959	$	(457)	$	(446)

(A)NDT Fund Income (Expense) includes gains and losses on NDT securities which are recorded in Net Gains (Losses) on Trust Investments. See Item 8. Note 10. 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 Net Other Income (Deductions), interest accretion expense on PSEG Power’s nuclear Asset Retirement Obligation (ARO) recorded in Operation & Maintenance (O&M) Expense and the depreciation related to the ARO asset recorded in Depreciation and Amortization (D&A) Expense.

(B)Net of tax (expense) benefit of $(74) million, $97 million and $(70) million for the years ended December 31, 2023, 2022 and 2021, respectively.

(C)Net of tax (expense)benefit of $(376) million, $178 million and $174 million for the years ended December 31, 2023, 2022 and 2021, respectively.

Our increase in Net Income for 2023 as compared to 2022 was driven primarily by

•changes in the MTM and NDT Fund as shown in the table above, and

•higher earnings due to continued investments in T&D clause programs at PSE&G,

•partially offset by a pension settlement charge in 2023 See Item 8. Note 12. Pension, Other Postretirement Benefits (OPEB) and Savings Plans, and

•lower pension and other postretirement benefit (OPEB) credits in 2023.

Our results of operations are primarily comprised of the results of operations of our principal operating segments, PSE&G and PSEG Power, excluding charges related to intercompany transactions, which are eliminated in consolidation. For additional information on intercompany transactions, see Item 8. Note 24. Related-Party Transactions.

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PSEG



							Increase / (Decrease)			Increase / (Decrease)
	Years Ended December 31,
	2023		2022		2021		2023 vs. 2022			2022 vs. 2021
	Millions						Millions		%	Millions		%
Operating Revenues	$	11,237	$	9,800	$	9,722	$	1,437	15	$	78	1
Energy Costs	3,260		4,018		3,499		(758)		(19)	519		15
Operation and Maintenance	3,150		3,178		3,226		(28)		(1)	(48)		(1)
Depreciation and Amortization	1,135		1,100		1,216		35		3	(116)		(10)
Losses on Asset Dispositions and Impairments	7		123		2,637		(116)		(94)	(2,514)		(95)
Income from Equity Method Investments	1		14		16		(13)		(93)	(2)		(13)
Net Gains (Losses) on Trust Investments	189		(265)		194		454		N/A	(459)		N/A
Net Other Income (Deductions)	172		124		98		48		39	26		27
Net Non-Operating Pension and OPEB (Costs) Credits	(218)		376		328		(594)		N/A	48		15
Loss on Extinguishment of Debt	—		—		(298)		—		N/A	298		N/A
Interest Expense	748		628		571		120		19	57		10
Income Tax Expense (Benefit)	518		(29)		(441)		547		N/A	412		(93)

The 2023, 2022 and 2021 amounts in the preceding table for Operating Revenues and O&M costs each include $533 million, $516 million and $511 million, respectively, for PSEG LI’s subsidiary, Long Island Electric Utility Servco, LLC (Servco). These amounts represent the O&M pass-through costs for the Long Island operations, the full reimbursement of which is reflected in Operating Revenues. See Item 8. Note 4. Variable Interest Entity for additional information. The following discussions for PSE&G and PSEG Power provide a detailed explanation of their respective variances.

PSE&G



	Years Ended December 31,						Increase / (Decrease)			Increase / (Decrease)
	2023		2022		2021		2023 vs. 2022			2022 vs. 2021
	Millions						Millions		%	Millions		%
Operating Revenues	$	7,807	$	7,935	$	7,122	$	(128)	(2)	$	813	11
Energy Costs	3,010		3,270		2,688		(260)		(8)	582		22
Operation and Maintenance (A)	1,843		1,838		1,692		5		—	146		9
Depreciation and Amortization	980		935		928		45		5	7		1
Gain on Asset Dispositions	—		—		(4)		—		—	4		N/A
Net Gains (Losses) on Trust Investments	—		(2)		2		2		N/A	(4)		N/A
Net Other Income (Deductions)	80		88		88		(8)		(9)	—		—
Net Non-Operating Pension and OPEB Credits	114		281		264		(167)		(59)	17		6
Interest Expense	493		427		402		66		15	25		6
Income Tax Expense	160		267		324		(107)		(40)	(57)		(18)

(A)Includes amortization of EE programs regulatory investment expenditures of $82 million, $48 million and $31 million for the years ended December 31, 2023, 2022 and 2021, respectively.

Year Ended December 31, 2023 as compared to 2022

Operating Revenues decreased $128 million due to changes in delivery, clause, commodity and other operating revenues.

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Delivery Revenues increased $184 million.

•Transmission revenues increased $112 million in revenue requirements attributable to higher rate base investment.

•Electric distribution and gas distribution revenues were $36 million higher due primarily to a decrease in the flowback to customers of excess deferred income tax liabilities and tax repair-related accumulated deferred income taxes, which is offset in Income Tax Expense.

•Electric distribution revenues increased $22 million due primarily to $38 million from Conservation Incentive Program (CIP) decoupling revenues and $16 million from an Energy Strong II rate roll-in, partially offset by a $34 million decrease in sales volumes.

•Gas distribution revenues increased $14 million due primarily to increases of $39 million from additional GSMP revenues in base rates and $24 million in CIP decoupling revenues, partially offset by $50 million from lower sales volumes.

Clause Revenues decreased $80 million due primarily to a $48 million net decrease in Tax Adjustment Credits (TAC) and Green Program Recovery Charge (GPRC) deferrals and $33 million in lower Societal Benefits Clause (SBC) collections. The changes in TAC and GPRC deferrals and SBC collections were entirely offset by the amortization of related costs (Regulatory Assets) in O&M, D&A and Interest and Income Tax Expenses. PSE&G does not earn margin on TAC and GPRC deferrals or on SBC collections.

Commodity Revenues decreased $289 million due to lower Gas revenues and Electric revenues. The changes in Commodity Revenues for both gas and electric are entirely offset by changes in Energy Costs. PSE&G earns no margin on the provision of basic gas supply service (BGSS) and basic generation service (BGS) to retail customers.

•Gas revenues decreased $254 million due to $133 million from lower BGSS sales volumes and $121 million from lower BGSS prices.

•Electric revenues decreased $35 million due primarily to $64 million from lower BGS sales volumes, partially offset by $29 million from higher prices.

Other Operating Revenues increased $57 million due primarily to a $45 million increase in Transition Renewable Energy Certificates (TREC) revenues, a $13 million increase in appliance service revenues, and a $9 million increase from the Successor Solar Incentive Program (SuSI), partially offset by an $18 million reduction in Solar Renewable Energy Credits (SREC) and ZEC revenues. The changes in TREC, SuSI, SREC and ZEC revenues are entirely offset by changes to Energy Costs.

Operating Expenses

Energy Costs decreased $260 million. This is offset by changes in Commodity Revenues and Other Operating Revenues.

Operation and Maintenance increased $5 million due primarily to increased amortization of EE programs regulatory investment expenditures and higher T&D expenditures, partially offset by decreases in other clause related and various other operational expenses.

Depreciation and Amortization increased $45 million due primarily to an increase in depreciation due to higher plant placed in service, partially offset by a net decrease in the amortization of Regulatory Assets and Liabilities.

Net Other Income (Deductions) decreased $8 million due primarily to lower Allowance for Funds Used During Construction and a reduction in solar loan interest income.

Net Non-Operating Pension and OPEB Credits decreased $167 million due primarily to an $86 million increase in interest cost, a $63 million decrease in the expected return on plan assets and a $62 million decrease in the amortization of service credits, partially offset by a $47 million decrease in amortization of the net actuarial loss.

Interest Expense increased $66 million due primarily to long-term debt net issuances at higher rates in 2023 and incremental issuances in 2022.

Income Tax Expense decreased $107 million due primarily to lower pre-tax income, an increase in the flowback of excess deferred income tax benefits, an increase in tax benefits from the CEF program investments, and an increase in bad debt write-offs.

Year Ended December 31, 2022 as compared to 2021

See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations in our Annual Report on Form 10-K for the year ended December 31, 2022 as filed with the SEC on February 22, 2023 for information related to the year ended December 31, 2022 as compared to 2021, which information is incorporated herein by reference.

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PSEG Power & Other



	Years Ended December 31,						Increase / (Decrease)			Increase / (Decrease)
	2023		2022		2021		2023 vs. 2022			2022 vs. 2021
	Millions						Millions		%	Millions		%
Operating Revenues	$	4,533	$	3,266	$	3,767	$	1,267	39	$	(501)	(13)
Energy Costs	1,353		2,149		1,978		(796)		(37)	171		9
Operation and Maintenance	1,307		1,340		1,534		(33)		(2)	(194)		(13)
Depreciation and Amortization	155		165		288		(10)		(6)	(123)		(43)
Losses on Asset Dispositions and Impairments	7		123		2,641		(116)		(94)	(2,518)		(95)
Income from Equity Method Investments	1		14		16		(13)		(93)	(2)		(13)
Net Gains (Losses) on Trust Investments	189		(263)		192		452		N/A	(455)		N/A
Net Other Income (Deductions)	96		36		10		60		N/A	26		N/A
Net Non-Operating Pension and OPEB (Costs) Credits	(332)		95		64		(427)		N/A	31		48
Loss on Extinguishment of Debt	—		—		(298)		—		N/A	298		N/A
Interest Expense	259		201		169		58		29	32		19
Income Tax Expense (Benefit)	358		(296)		(765)		654		N/A	469		(61)

Year Ended December 31, 2023 as compared to 2022

Operating Revenues increased $1,267 million due primarily to changes in generation and gas supply and other operating revenues.

Generation Revenues increased $1,868 million due primarily to

•a net increase of $2,023 million due to MTM gains in 2023 as compared to MTM losses in 2022. Of this amount, there was a $1,539 million increase due to changes in forward prices in 2023 as compared to 2022 coupled with a $484 million increase due to positions reclassified to realized upon settlement, and

•a net increase of $99 million due primarily to higher average realized prices and volumes sold in 2023 in the PJM region, partially offset by volumes sold in the New England and New York regions in 2022 related to the fossil generating plants sold in February 2022 and lower ZEC revenue,

•partially offset by a net decrease of $190 million due primarily to electricity sold under the BGS contracts, which ended in May 2023, and lower volumes of other load contracts, and

•a net decrease of $57 million in capacity revenue due primarily to the sale of the fossil generating plants coupled with lower capacity prices in the PJM region, partially offset by decreases in capacity expenses due to lower load volumes served.

Gas Supply Revenues decreased $619 million due primarily to

•a net decrease of $288 million related to sales to third parties, due primarily to $384 million from lower sales prices, partially offset by $96 million from higher sales volumes,

•a net decrease of $275 million in sales under the BGSS contract due to $148 million from lower sales volumes and $127 million due to lower prices, and

•a net decrease of $56 million due primarily to MTM losses in 2023 as compared to MTM gains in 2022. Of this amount, there was a $29 million decrease due to positions reclassified to realized upon settlement, coupled with a $27 million decrease due 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

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$796 million due to

Gas costs decreased $536 million due primarily to

•a net decrease of $273 million related to sales under the BGSS contract, of which $143 million was due to the lower average cost of gas and $130 million due to lower send out volumes, and

•a net decrease of $261 million related to sales to third parties, due primarily to $332 million from the lower average cost of gas, partially offset by $71 million due to higher volumes sold.

Generation costs decreased $260 million due primarily to

•a net decrease of $185 million in fuel and emission costs due primarily to the sale of the fossil generating plants, and

•a net decrease of $65 million in energy purchases due primarily to lower renewable energy credit requirements caused by decreases in load served in the PJM region.

Operation and Maintenance decreased $33 million due primarily to the sale of the fossil generating plants in February 2022.

Losses on Asset Dispositions and Impairments The $7 million loss in 2023 reflects an impairment at Energy Holdings related to one of its real estate assets. The $123 million loss in 2022 reflects an impairment loss of $78 million at Energy Holdings related to one of its domestic energy generating facilities and its real estate assets, and a $50 million impairment loss due to the sale of the fossil generating plants in February 2022, partially offset by a $5 million gain on a land sale at PSEG Power. See Item 8. Note 3. Asset Dispositions and Impairments.

Income from Equity Method Investments decreased $13 million due primarily to the sale of our ownership interest in Kalaeloa completed in July 2023.

Net Gains (Losses) on Trust Investments increased $452 million due primarily to NDT investments with $146 million of net unrealized gains on equity securities in 2023 as compared to $205 million of net unrealized losses in 2022 and $42 million of net realized gains in 2023 as compared to $50 million in net realized losses in 2022.

Net Other Income (Deductions) increased $60 million due primarily to purchases of net operating loss (NOL) tax benefits under the New Jersey Technology Tax Benefit Transfer Program in 2022 and higher interest income in 2023.

Net Non-Operating Pension and OPEB (Costs) Credits increased $427 million due primarily to the pension lift-out settlement charge, a decrease in the expected return on plan assets, an increase in interest cost, and a decrease in the amortization of the net prior service credit.

Interest Expense increased $58 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 in 2023.

Income Tax Expense increased $654 million due primarily to higher pre-tax income in 2023.

Year Ended December 31, 2022 as compared to 2021

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.

Financing Methodology

We expect our capital requirements to be met through internally generated cash flows and external financings, consisting of short-term debt for working capital needs and long-term debt for capital investments.

PSE&G’s sources of external liquidity include a $1 billion multi-year revolving credit facility. PSE&G uses internally generated cash flow and its commercial paper program to meet seasonal, intra-month and temporary working capital needs. PSE&G does not engage in any intercompany borrowing or lending arrangements. PSE&G maintains back-up credit facilities in an amount sufficient to cover the commercial paper and letters of credit outstanding. PSE&G’s dividend payments to/capital contributions from PSEG are consistent with its capital structure objectives which have been established to maintain investment grade credit ratings. PSE&G’s long-term financing plan is designed to replace maturities, fund a portion of its capital program

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and manage short-term debt balances. Generally, PSE&G uses either secured medium-term notes or first mortgage bonds to raise long-term capital.

PSEG, PSEG Power, Energy Holdings, PSEG LI and Services participate in 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. 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.

PSEG and PSEG Power have access through sub-limits to a revolving Master Credit Facility, which provides for $2.75 billion of multi-year credit capacity. The current PSEG sub-limit is $1.5 billion and current PSEG Power sub-limit is $1.25 billion. Sub-limits can be adjusted subject to the terms of the Master Credit Facility.

PSEG’s available sources of external liquidity may include the issuance of long-term debt securities and the incurrence of additional indebtedness through our commercial paper program back-stopped by our credit facilities. Our current sources of external liquidity include the Master Credit Facility. This facility is available to back-stop PSEG’s commercial paper program, issue letters of credit and for general corporate purposes. PSEG’s Master Credit Facility and the commercial paper program are available to support PSEG’s working capital needs and are also available to make equity contributions or provide liquidity support to its subsidiaries. Additionally, from time to time, PSEG enters into short-term loan agreements designed to enhance its liquidity position.

PSEG Power’s sources of external liquidity include the Master Credit Facility and PSEG Power’s letter of credit facilities. Credit capacity is primarily used to provide collateral in support of PSEG Power’s forward energy sale and forward fuel purchase contracts as the market prices for energy and fuel fluctuate, and to meet potential collateral postings in the event that PSEG Power is downgraded to below investment grade by Standard & Poor’s (S&P) or Moody’s. PSEG Power’s dividend payments to PSEG are also designed to be consistent with its capital structure objectives which have been established to maintain investment grade credit ratings and provide sufficient financial flexibility.

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 dividends.

For the year ended December 31, 2023, our operating cash flow increased $2,303 million. The net increase was primarily due to an inflow of $1,408 million in net cash collateral postings in 2023 as compared to a $677 million outflow in 2022 at PSEG Power and lower tax payments in 2023, partially offset by a net change at PSE&G, as discussed below.

PSE&G

PSE&G’s operating cash flow decreased $488 million from $2,028 million to $1,540 million for the year ended December 31, 2023, as compared to 2022, due primarily to lower cash collateral postings received from BGS suppliers, increases in materials and supplies to support our electric AMI and other infrastructure programs, an increase in vendor and electric energy payments, and a net increase in regulatory deferrals. This was partially offset by a decrease in net accounts receivable due to improved collections following the delays from COVID-19 moratoriums.

Short-Term Liquidity

PSEG meets its short-term liquidity requirements, as well as those of PSEG Power, primarily through the issuance of commercial 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 facility.

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.

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. In August 2023, PSEG repaid $250 million of the $750 million 364-day variable rate term loan that was issued in April 2023.These term loans are not included in the credit facility amounts presented in the following table.

In December 2023, PSEG Power converted a $100 million letter of credit facility from committed to uncommitted. PSEG Power also decreased a letter of credit facility, from $100 million to $75 million.

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Our total committed credit facilities and available liquidity as of December 31, 2023 were as follows:



Company/Facility	As of December 31, 2023
	Total Facility		Usage		Available Liquidity
	Millions
PSEG	$	1,500	$	27	$	1,473
PSE&G	1,000		445		555
PSEG Power	1,525		188		1,337
Total	$	4,025	$	660	$	3,365

For additional information, see Item 8. Note 14. Debt and Credit Facilities.

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 December 31, 2023, our liquidity position, including our credit facilities and access to external financing, was expected to be sufficient to meet our projected stressed requirements over our 12-month planning horizon. PSEG analyzes its liquidity requirements using stress scenarios that consider different events, including changes in commodity prices and the potential impact of PSEG Power losing its investment grade credit rating from S&P or Moody’s, which would represent a two level downgrade from its current Moody’s and S&P ratings. In the event of a deterioration of PSEG Power’s 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 $751 million and $878 million as of December 31, 2023 and 2022, respectively. See Item 8. Note 13. Commitments and Contingent Liabilities for additional discussion of PSEG Power’s agreements.

Long-Term Debt Financing

During the next twelve months,

•PSEG has $750 million of 2.88% of Senior Notes maturing in June 2024,

•PSE&G has $250 million of 3.75% of Medium-Term Notes Series I, due March 2024,

•PSE&G has $250 million of 3.15% of Medium-Term Notes, Series J, due August 2024, and

•PSE&G has $250 million of 3.05% of Medium-Term Notes, Series J, due November 2024.

For additional information, see Item 8. Note 14. Debt and Credit Facilities.

NDT Fund Obligation

The NRC requires a biennial filing of the NDT fund balances against the decommissioning liability estimate. Any funding shortfalls are required to be cured prior to the next NDT reporting period. We do not currently expect to be required to provide supplemental funding of the NDT Fund.

Debt Covenants

Our credit agreements contain maximum debt to equity ratios and other restrictive covenants and conditions to borrowing. We are currently in compliance with all of our debt covenants. Continued compliance with applicable financial covenants will depend upon our future financial position, level of earnings and cash flows, as to which no assurances can be given.

In addition, under its First and Refunding Mortgage (Mortgage), PSE&G may issue new First and Refunding Mortgage Bonds against previous additions and improvements, provided that its ratio of earnings to fixed charges calculated in accordance with its Mortgage is at least 2 to 1, and/or against retired Mortgage Bonds. As of December 31, 2023, PSE&G’s Mortgage coverage ratio was 3.8 to 1 and the Mortgage would permit up to approximately $9.3 billion aggregate principal amount of new Mortgage Bonds to be issued against additions and improvements to its property.

Default Provisions

Our bank credit agreements and indentures contain various, customary default provisions that could result in the potential acceleration of indebtedness under the defaulting company’s agreement.

In particular, PSEG’s bank credit agreements contain provisions under which certain events, including an acceleration of material indebtedness under PSE&G’s and PSEG Power’s respective financing agreements, a failure by PSE&G or PSEG Power to satisfy certain final judgments and certain bankruptcy events by PSE&G or PSEG Power, would constitute an event of

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default under the PSEG bank credit agreements. Under the PSEG bank credit agreements, it would also be an event of default if either PSE&G or PSEG Power ceases to be wholly owned by PSEG. The PSE&G and PSEG Power bank credit agreements include similar default provisions; however, such provisions only relate to the respective borrower under such agreement and its subsidiaries and do not contain cross default provisions to each other. The PSE&G and PSEG Power bank credit agreements do not include cross default provisions relating to PSEG. Each of PSE&G’s and PSEG Power’s bank credit agreements also contain limitations on the incurrence of liens by it and certain of its subsidiaries and PSEG Power’s bank credit agreements contain restrictions on the incurrence of certain subsidiary debt.

PSEG’s existing notes include a cross acceleration provision that may be triggered upon the acceleration of more than $75 million of indebtedness incurred by PSEG. Such provision does not extend to an acceleration of indebtedness by any of PSEG’s subsidiaries. Under PSE&G’s medium-term note indenture, an event of default under PSE&G’s mortgage indenture and acceleration of the mortgage bonds would constitute an event of default.

Ratings Triggers

Our debt indentures and credit agreements do not contain any material “ratings triggers” that would cause an acceleration of the required interest and principal payments in the event of a ratings downgrade. However, in the event of a downgrade, any one or more of the affected companies may be subject to increased interest costs on certain bank debt and certain collateral requirements. In the event that we are not able to affirm representations and warranties on credit agreements, lenders would not be required to make loans.

In accordance with BPU requirements under the BGS contracts, PSE&G is required to maintain an investment grade credit rating. If PSE&G were to lose its investment grade rating, it would be required to file a plan to assure continued payment for the BGS requirements of its customers.

Fluctuations in commodity prices or a deterioration of PSEG Power’s credit rating to below investment grade could increase PSEG Power’s required margin postings under various agreements entered into in the normal course of business. PSEG Power believes it has sufficient liquidity to meet the required posting of collateral which would result from a credit rating downgrade to below investment grade by S&P or Moody’s at today’s market prices.

Common Stock Dividends



	Years Ended December 31,
Dividend Payments on Common Stock	2023		2022		2021
Per Share	$	2.28	$	2.16	$	2.04
in Millions	$	1,137	$	1,079	$	1,031

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 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 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.

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Moody’s (A)

S&P (B)

PSEG

Outlook

Stable

Senior Notes

Baa2

BBB

Commercial Paper

PSE&G

Outlook

Stable

Mortgage Bonds

Commercial Paper

PSEG Power

Outlook

Positive

Stable

Issuer Rating

Baa2

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.

(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.

Other Comprehensive Income

For the year ended December 31, 2023, we had Other Comprehensive Income of $371 million on a consolidated basis. The Other Comprehensive Income was due primarily to $324 million related to pension and other postretirement benefits, $41 million of net unrealized gains related to available-for-sale debt securities, and $6 million of unrealized gains on derivative contracts accounted for as hedges. See Item 8. Note 21. Accumulated Other Comprehensive Income (Loss), Net of Tax for additional information.

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. Projected capital construction and investment expenditures, excluding nuclear fuel purchases, for the next three years are presented in the following table. These projections include Allowance for Funds Used During Construction for PSE&G and Interest Capitalized During Construction for PSEG’s other subsidiaries. These amounts are subject to change, based on various factors. Amounts shown below for PSE&G include currently approved programs. We intend to continue to invest in infrastructure modernization and will seek to extend these and related programs as appropriate.



	2024		2025		2026
			Millions
PSE&G:
Transmission	$	610	$	785	$	725
Electric Distribution	1,155		1,160		1,255
Gas Distribution	1,145		1,090		1,095
Clean Energy	440		605		585
Total PSE&G	$	3,350	$	3,640	$	3,660
Competitively Bid, FERC Regulated Transmission	15		70		240
PSEG Power & Other	265		205		170
Total PSEG	$	3,630	$	3,915	$	4,070

PSE&G

PSE&G’s projections for future capital expenditures include material additions and replacements to its T&D systems to meet expected growth and to manage reliability. As project scope and cost estimates develop, PSE&G will modify its current projections to include these required investments. PSE&G’s projected expenditures for the various items reported above are primarily comprised of the following:

•Transmission—investments focused on reliability improvements and replacement of aging infrastructure.

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•Electric and Gas Distribution—investments for new business, reliability improvements, flood mitigation, and modernization and replacement of equipment that has reached the end of its useful life.

•Clean Energy—investments associated with customer EE programs, infrastructure supporting EVs and grid-connected solar.

In 2023, PSE&G made $2,998 million of capital expenditures, primarily for T&D system reliability. In addition, PSE&G had cost of removal, net of salvage, of $166 million associated with capital replacements, and expenditures for EE programs of approximately $466 million, which are included in operating cash flows.

Competitively Bid, FERC Regulated Transmission

In December 2023, PJM awarded a subsidiary of Energy Holdings a project to address increasing load and reliability issues in Maryland as part of its 2022 Window 3 competitive solicitation.

PSEG Power & Other

PSEG’s other projected expenditures are primarily comprised of investments to maintain and enhance current nuclear operations and opportunities to increase nuclear generation at PSEG Power and to purchase software and office equipment at Services.

In 2023, PSEG Power & Other made capital expenditures of $140 million, excluding $187 million for nuclear fuel, primarily related to various nuclear projects at PSEG Power and to purchase hardware, software and office equipment at Services.

Other Material Cash Requirements

The following table reflects our other material cash requirements which include debt maturities and interest payments, operating lease payments and energy related purchase commitments in the respective periods in which they are due. For additional information, see Item 8. Note 14. Debt and Credit Facilities, Note 7. Leases and Note 13. Commitments and Contingent Liabilities.

The table below does not reflect any anticipated cash payments for pension and OPEB or AROs due to uncertain timing of payments. See Item 8. Note 12. Pension, Other Postretirement Benefits (OPEB) and Savings Plans and Note 11. Asset Retirement Obligations (AROs) for additional information.



	Total Amount Committed		Less Than 1 Year		2 - 3 Years		4 - 5 Years		Over 5 Years
	Millions
Long-Term Recourse Debt Maturities
PSEG	$	4,396	$	750	$	550	$	1,300	$	1,796
PSE&G	13,765		750		1,225		1,125		10,665
PSEG Power	1,250		—		1,250		—		—
Interest on Recourse Debt
PSEG	877		153		277		231		216
PSE&G	7,997		506		955		898		5,638
PSEG Power (A)	79		66		13		—		—
Operating Leases
PSE&G	125		18		28		22		57
Other	111		17		33		33		28

Energy-Related Purchase Commitments
PSEG Power	2,486		745		981		524		236
Total	$	31,086	$	3,005	$	5,312	$	4,133	$	18,636

(A)Based on a blended rate including effects of floating to fixed rate hedging transacted at the Parent level.

CRITICAL ACCOUNTING ESTIMATES

Under accounting guidance generally accepted in the United States (GAAP), many accounting standards require the use of estimates, variable inputs and assumptions (collectively referred to as estimates) that are subjective in nature. Because of this, differences between the actual measure realized versus the estimate can have a material impact on results of operations,

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financial position and cash flows. We have determined that the following estimates are considered critical to the application of rules that relate to the respective businesses.

Accounting for Pensions and Other Postretirement Benefits (OPEB)

The market-related value of plan assets held for PSEG’s qualified pension and OPEB plans is equal to the fair value of these assets as of year-end. The plan assets are comprised of investments in both debt and equity securities which are valued using quoted market prices, broker or dealer quotations, or alternative pricing sources with reasonable levels of price transparency. Plan assets also include investments in unlisted real estate which is valued via third-party appraisals. We calculate pension and OPEB costs using various economic and demographic assumptions.

Assumptions and Approach Used: Economic assumptions include the discount rate and the expected rate of return on plan assets. Demographic pension and OPEB assumptions include projections of future mortality rates, pay increases and retirement patterns, as well as projected health care costs for OPEB.



Assumption	2023		2022		2021
Pension
Discount Rate	5.02	%	5.20	%	2.94	%
Expected Rate of Return on Plan Assets	8.10	%	7.20	%	7.70	%
OPEB
Discount Rate	4.96	%	5.16	%	2.82	%
Expected Rate of Return on Plan Assets	8.10	%	7.20	%	7.69	%

The discount rate used to calculate PSEG’s pension and OPEB obligations is determined as of December 31 each year, our measurement date. The discount rate is determined by developing a spot rate curve based on the yield to maturity of a universe of high quality corporate bonds with similar maturities to the plan obligations. The spot rates are used to discount the estimated plan distributions. The discount rate is the single equivalent rate that produces the same result as the full spot rate curve.

Our expected rate of return on plan assets reflects current asset allocations, historical long-term investment performance and an estimate of future long-term returns by asset class, long-term inflation assumptions and a premium for active management.

We utilize a corridor approach that reduces the volatility of reported costs/credits. The corridor requires differences between actuarial assumptions and plan results be deferred and amortized as part of the costs/credits. This occurs only when the accumulated differences exceed 10% of the greater of the benefit obligation or the fair value of plan assets as of each year-end. For one of PSEG’s qualified pension plans, the excess would be amortized over the average remaining expected life of inactive participants, which is approximately eighteen years. For PSEG’s other qualified pension plan, the excess would be amortized over the average remaining service period of active employees, which is approximately fifteen years.

Effect if Different Assumptions Used: As part of the business planning process, we have modeled future costs assuming an 8.10% expected rate of return and a 5.02% discount rate for 2024 pension costs/credits and a 4.96% discount rate for 2024 OPEB costs/credits. Based upon these assumptions, we have estimated a net periodic pension expense in 2024 of approximately $21 million, or a net periodic pension credit of $19 million, net of amounts capitalized, and a net periodic OPEB expense in 2024 of approximately $6 million, or $5 million, net of amounts capitalized. Beginning in 2023, our net periodic pension amounts include the impact of the accounting order approved by the BPU authorizing PSE&G to modify its pension accounting for ratemaking purposes. See a discussion in Item 7. MD&A—Executive Overview of 2023 and Future Outlook for further details. Actual future pension costs/credits and funding levels will depend on future investment performance, changes in discount rates, market conditions, funding levels relative to our projected benefit obligation and accumulated benefit obligation and various other factors related to the populations participating in the pension plans. Actual future OPEB costs/credits will depend on future investment performance, changes in discount rates, market conditions, and various other factors.

The following chart reflects the sensitivities associated with a change in certain assumptions. The effects of the assumption changes shown in the chart solely reflect the impact of that specific assumption and therefore does not reflect the impact of the 2023 BPU accounting order.

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	% Change	Impact on Benefit Obligation as of December 31, 2023		Increase to Costs in 2024		Increase to Costs, net of Amounts Capitalized in 2024
Assumption		Millions
Pension
Discount Rate	(1)%	$	536	$	23	$	16
Expected Rate of Return on Plan Assets	(1)%	N/A		$	40	$	40
OPEB
Discount Rate	(1)%	$	72	$	(2)	$	(3)
Expected Rate of Return on Plan Assets	(1)%	N/A		$	4	$	4

See Item 7A. Quantitative and Qualitative Disclosures About Market Risk for additional information.

Derivative Instruments

The operations of PSEG, PSEG Power and PSE&G are exposed to market risks from changes in commodity prices, interest rates and equity prices that could affect their results of operations and financial condition. Exposure to these risks is managed through normal operating and financing activities and, when appropriate, through executing derivative transactions. Derivative instruments are used to create a relationship in which changes to the value of the assets, liabilities or anticipated transactions exposed to market risks are expected to be offset by changes in the value of these derivative instruments.

Current accounting guidance requires us to recognize all derivatives on the balance sheet at their fair value, except for derivatives that qualify for and are designated as normal purchases and normal sales contracts.

Assumptions and Approach Used: In general, the fair value of our derivative instruments is determined primarily by end of day clearing market prices from an exchange, such as the New York Mercantile Exchange, Intercontinental Exchange and Nodal Exchange, or auction prices.

For our wholesale energy business, many of the forward sale, forward purchase, option and other contracts are derivative instruments that hedge commodity price risk, but do not meet the requirements for, or are not designated as, either cash flow or fair value hedge accounting. The changes in value of such derivative contracts are marked to market through earnings as the related commodity prices fluctuate. As a result, our earnings may experience significant fluctuations depending on the volatility of commodity prices.

Effect if Different Assumptions Used: Any significant changes to the fair market values of our derivatives instruments could result in a material change in the value of the assets or liabilities recorded on our Consolidated Balance Sheets and could result in a material change to the unrealized gains or losses recorded in our Consolidated Statements of Operations.

For additional information regarding Derivative Financial Instruments, see Item 8. Note 1. Organization, Basis of Presentation and Summary of Significant Accounting Policies, Note 16. Financial Risk Management Activities and Note 17. Fair Value Measurements.

Long-Lived Assets

Management evaluates long-lived assets for impairment and reassesses the reasonableness of their related estimated useful lives whenever events or changes in circumstances warrant assessment. Such events or changes in circumstances may be as a result of significant adverse changes in regulation, business climate, counterparty credit worthiness, market conditions, or a determination that it is more-likely-than-not that an asset or asset group will be sold or retired before the end of its estimated useful life.

Assumptions and Approach Used: In the event certain triggers exist indicating an asset/asset group may not be recoverable, an undiscounted cash flow test is performed to determine if an impairment exists. When the carrying value of a long-lived asset/asset group exceeds the undiscounted estimate of future cash flows associated with the asset/asset group, an impairment may exist to the extent that the fair value of the asset/asset group is less than its carrying amount.

For PSEG Power, cash flows for long-lived assets and asset groups are determined at the lowest level for which identifiable cash flows are largely independent of the cash flows of other assets and liabilities. The cash flows from the nuclear generation units are evaluated at the portfolio level. These tests require significant estimates and judgment when developing expected future cash flows. Significant inputs may include, but are not limited to, forward power prices, expectation of PTCs, ZEC payments for the New Jersey nuclear assets, fuel costs, other operating and capital expenditures, the cost of borrowing and asset sale prices and probabilities associated with any potential sale prior to the end of the estimated useful life or the early retirement of assets. The assumptions used by management incorporate inherent uncertainties that are at times difficult to predict and could

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result in impairment charges or accelerated depreciation in future periods if actual results materially differ from the estimated assumptions utilized in our forecasts.

In addition, long-lived assets are depreciated under the straight-line method based on estimated useful lives. An asset’s operating useful life is generally based upon operational experience with similar asset types and other non-operational factors. In the ordinary course, management, together with an asset’s co-owners in the case of certain of our jointly-owned assets, make a number of decisions that impact the operation of our generation assets beyond the current year. These decisions may have a direct impact on the estimated remaining useful lives of our assets and will be influenced by the financial outlook of the assets, including future market conditions such as forward energy and capacity prices, operating and capital investment costs and any state or federal legislation and regulations, among other items.

Effect if Different Assumptions Used: The above cash flow tests, and fair value estimates and estimated remaining useful lives may be impacted by a change in the assumptions noted above and could significantly impact the outcome, triggering additional impairment tests, write-offs or accelerated depreciation. For additional information on the potential impacts on our future financial statements that may be caused by a change in the assumptions noted above, see Item 8. Note 3. Asset Dispositions and Impairments.

Asset Retirement Obligations (ARO)

PSE&G, PSEG Power and Services recognize liabilities for the expected cost of retiring long-lived assets for which a legal obligation exists. These AROs are recorded at fair value in the period in which they are incurred and are capitalized as part of the carrying amount of the related long-lived assets. PSE&G, as a rate-regulated entity, recognizes Regulatory Assets or Liabilities as a result of timing differences between the recording of costs and costs recovered through the rate-making process. We accrete the ARO liability to reflect the passage of time with the corresponding expense recorded in O&M Expense.

Assumptions and Approach Used: Because quoted market prices are not available for AROs, we estimate the initial fair value of an ARO by calculating discounted cash flows that are dependent upon various assumptions, including:

•estimation of dates for retirement, which can be dependent on environmental and other legislation,

•amounts and timing of future cash expenditures associated with retirement, settlement or remediation activities,

•discount rates,

•cost escalation rates,

•market risk premium,

•inflation rates, and

•if applicable, past experience with government regulators regarding similar obligations.

We obtain updated nuclear decommissioning cost studies triennially unless new information necessitates more frequent updates. The most recent cost study was done in 2021. When we revise any assumptions used to calculate fair values of existing AROs, we adjust the ARO balance and corresponding long-lived asset which generally impacts the amount of accretion and depreciation expense recognized in future periods.

Nuclear Decommissioning AROs

AROs related to the future decommissioning of PSEG Power’s nuclear facilities comprised approximately 72% or $1,057 million of PSEG’s total AROs as of December 31, 2023. PSEG Power determines its AROs for its nuclear units by assigning probability weighting to various discounted cash flow outcomes for each of its nuclear units that incorporate the assumptions above as well as:

•license renewals,

•SAFSTOR alternative, which assumes the nuclear facility can be safely stored and subsequently decommissioned in a period within 60 years after operations,

•DECON alternative, which assumes decommissioning activities begin after operations,

•recovery from the federal government of assumed specific costs incurred for spent nuclear fuel, and

•financial feasibility and impacts on potential early shutdown.

Effect if Different Assumptions Used: Changes in the assumptions could result in a material change in the ARO balance sheet obligation and the period over which we accrete to the ultimate liability. Had the following assumptions been applied, our estimates of the approximate impacts on the Nuclear ARO as of December 31, 2023 are as follows:

•A decrease of 1% in the discount rate would result in a $43 million increase in the Nuclear ARO.

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•An increase of 1% in the inflation rate would result in a $303 million increase in the Nuclear ARO.

•If the federal government were to discontinue reimbursing us for assumed specific spent fuel costs as prescribed under the Nuclear Waste Policy Act, the Nuclear ARO would increase by $139 million.

•If we would elect or be required to decommission under a DECON alternative at Salem and Hope Creek, the Nuclear ARO would increase by $497 million.

Accounting for Regulated Businesses

PSE&G prepares its financial statements to comply with GAAP for rate-regulated enterprises, which differs in some respects from accounting for non-regulated businesses. In general, accounting for rate-regulated enterprises should reflect the economic effects of regulation. As a result, a regulated utility is required to defer the recognition of costs (Regulatory Asset) or recognize obligations (Regulatory Liability) if the rates established are designed to recover the costs and if the competitive environment makes it probable that such rates can be charged or collected. This accounting results in the recognition of revenues and expenses in different time periods than that of enterprises that are not regulated.

Assumptions and Approach Used: PSE&G recognizes Regulatory Assets where it is probable that such costs will be recoverable in future rates from customers and Regulatory Liabilities where it is probable that refunds will be made to customers in future billings. The highest degree of probability is an order from the BPU either approving recovery of the deferred costs over a future period or requiring the refund of a liability over a future period.

Virtually all of PSE&G’s Regulatory Assets and Regulatory Liabilities are supported by BPU orders. In the absence of an order, PSE&G will consider the following when determining whether to record a Regulatory Asset or Liability:

•past experience regarding similar items with the BPU,

•treatment of a similar item in an order by the BPU for another utility,

•passage of new legislation, and

•recent discussions with the BPU.

All deferred costs are subject to prudence reviews by the BPU. When the recovery of a Regulatory Asset or payment of a Regulatory Liability is no longer probable, PSE&G charges or credits earnings, as appropriate.

Effect if Different Assumptions Used: A change in the above assumptions may result in a material impact on our results of operations or our cash flows. See Item 8. Note 6. Regulatory Assets and Liabilities for a description of the amounts and nature of regulatory balance sheet amounts.

ITEM 7A. 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 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, treasury locks, 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.

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MTM VaR consists of MTM derivatives that are economic hedges. The calculation does not include market risks associated with activities that are subject to accrual accounting, primarily our generating facilities and some 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.



	MTM VaR
	Years Ended December 31,
	2023		2022
	Millions
95% Confidence Level, Loss could exceed VaR one day in 20 days
Period End	$	48	$	122
Average for the Period	$	56	$	152
High	$	127	$	365
Low	$	24	$	70

99.5% Confidence Level, Loss could exceed VaR one day in 200 days
Period End	$	75	$	191
Average for the Period	$	87	$	239
High	$	198	$	572
Low	$	38	$	110

See Item 8. Note 16. Financial Risk Management Activities for a discussion of credit risk.

Interest Rates

We are subject to the risk of fluctuating interest rates in the normal course of business. We manage interest rate risk by targeting a balanced debt maturity profile which limits refinancing in any given period or interest rate environment. In addition, we use a mix of fixed and floating rate debt, interest rate swaps and interest rate lock agreements.

As of December 31, 2023, a hypothetical 10% increase in market interest rates would result in an additional $2 million in pre-tax annual interest costs related to either the current or the long-term portion of long-term debt, and term loan agreements.

Debt and Equity Securities

As of December 31, 2023, we had $4.6 billion of net assets in trust for our pension and OPEB plans. Although fluctuations in market prices of securities within this portfolio do not directly affect our earnings in the current period, changes in the value of these investments could affect

•our future contributions to these plans,

•our financial position if our accumulated benefit obligation under our pension plans exceeds the fair value of the pension trust funds, and

•future earnings, as we could be required to adjust pension expense and the assumed rate of return.

The NDT Fund is comprised primarily of fixed income and equity securities. As of December 31, 2023, the portfolio included $1.3 billion of equity securities inclusive of $0.3 billion of investments in listed real assets, and $1.2 billion in fixed income securities. The fair market value of the assets in the NDT Fund will fluctuate primarily depending upon the performance of equity markets. As of December 31, 2023, a hypothetical 10% change in the equity market would impact the value of the equity securities in the NDT Fund by approximately $131 million.

We use duration to measure the interest rate sensitivity of the fixed income portfolio. Duration is a summary statistic of the effective average maturity of the fixed income portfolio. The benchmark for the fixed income component of the NDT Fund currently has a duration of 6.24 years and a yield of 4.53%. The portfolio’s value will appreciate or depreciate by the duration with a 1% change in interest rates. As of December 31, 2023, a hypothetical 1% increase in interest rates would result in a decline in the market value for the fixed income portfolio of approximately $76 million.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

This combined Form 10-K is separately filed by PSEG and PSE&G. Information contained herein relating to any individual company is filed by such company on its own behalf. PSE&G makes representations only as to itself and makes no representations as to any other company.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of

Public Service Enterprise Group Incorporated

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Public Service Enterprise Group Incorporated and subsidiaries (the “Company” or PSEG) as of December 31, 2023 and 2022, the related consolidated statements of operations, comprehensive income (loss), stockholders' equity, and cash flows, for each of the three years in the period ended December 31, 2023, the related notes and the consolidated financial statement schedule listed in the Index at Item 15(B)(a) (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2023 and 2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2023, in conformity with accounting principles generally accepted in the United States of America.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company's internal control over financial reporting as of December 31, 2023, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated February 26, 2024, expressed an unqualified opinion on the Company's internal control over financial reporting.

Basis for Opinion

These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matter

The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

Accounting for the Effects of Regulation – Refer to Notes 1 and 6 to the financial statements

Critical Audit Matter Description

PSEG’s subsidiary, Public Service Electric and Gas Company (PSE&G), prepares its financial statements to comply with GAAP for rate-regulated enterprises, which differs in some respects from accounting for non-regulated businesses. Management believes that PSE&G’s transmission and distribution businesses continue to meet the accounting requirements for rate-regulated entities, and PSE&G’s financial statements reflect the economic effects of regulation. PSE&G has deferred certain costs based on rate orders issued by the New Jersey Board of Public Utilities (“BPU”) or Federal Energy Regulatory Commission (“FERC”) or based on PSE&G’s experience with prior rate proceedings.

PSE&G defers the recognition of costs as a regulatory asset or records the recognition of obligations as a regulatory liability if it is probable that, through the rate-making process, there will be a corresponding increase or decrease in future rates. This accounting results in the recognition of revenues and expenses in different time periods than that of enterprises that are not regulated. Regulatory assets and other investments and costs incurred under various infrastructure filings and clause mechanisms are subject to prudence reviews and can be disallowed in the future by regulatory authorities. To the extent that

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collection of any infrastructure or clause mechanism revenue, regulatory assets or payments of regulatory liabilities is no longer probable, the amounts would be charged or credited to income.

We identified the accounting for the effects of rate regulation as a critical audit matter due to the significant judgments made by management in assessing the probable recovery of regulatory assets and incurred costs or the likelihood of refunds of regulatory liabilities. Auditing these judgments required specialized knowledge of accounting for rate regulation and the ratemaking process due to its inherent complexities.

How the Critical Audit Matter Was Addressed in the Audit

Our audit procedures to evaluate the accounting for the effects of cost-based rate regulation, including the probable recovery or refund of regulatory assets and liabilities, included the following, among others:

•We tested the effectiveness of management's controls over the evaluation of the likelihood of (1) the recovery in future rates of costs deferred as regulatory assets, and (2) a refund or a future reduction in rates that should be reported as regulatory liabilities. We tested the effectiveness of management's controls over the initial recognition of amounts as regulatory assets or liabilities and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates.

•We obtained and read relevant regulatory orders issued by the BPU and FERC for PSE&G and other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the treatment of similar costs under similar circumstances. We evaluated the external information and compared it to management’s recorded regulatory asset and liability balances for completeness.

•For regulatory matters in process, we inspected associated documents and testimony filed with the BPU or FERC for any evidence that might contradict management's assertions.

•We evaluated the financial statement presentation and disclosures related to the impacts of cost-based rate-regulation, including the balances recorded and regulatory developments.



/s/ DELOITTE & TOUCHE LLP

Morristown, New Jersey
February 26, 2024

We have served as the Company's auditor since 1934.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Sole Stockholder of

Public Service Electric and Gas Company

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Public Service Electric and Gas Company and subsidiaries (the “Company” or PSE&G) as of December 31, 2023 and 2022, the related consolidated statements of operations, comprehensive income, common stockholder’s equity, and cash flows, for each of the three years in the period ended December 31, 2023, the related notes and the consolidated financial statement schedule listed in the Index at Item 15(B)(b) (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2023 and 2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2023, in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matter

Accounting for the Effects of Regulation – Refer to Notes 1 and 6 to the financial statements

Critical Audit Matter Description

PSE&G prepares its financial statements to comply with GAAP for rate-regulated enterprises, which differs in some respects from accounting for non-regulated businesses. Management believes that PSE&G’s transmission and distribution businesses continue to meet the accounting requirements for rate-regulated entities, and PSE&G’s financial statements reflect the economic effects of regulation. PSE&G has deferred certain costs based on rate orders issued by the New Jersey Board of Public Utilities (“BPU”) or Federal Energy Regulatory Commission (“FERC”) or based on PSE&G’s experience with prior rate proceedings.

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collection of any infrastructure or clause mechanism revenue, regulatory assets or payments of regulatory liabilities is no longer probable, the amounts would be charged or credited to income.

How the Critical Audit Matter Was Addressed in the Audit

• We tested the effectiveness of management's controls over the evaluation of the likelihood of (1) the recovery in future rates of costs deferred as regulatory assets, and (2) a refund or a future reduction in rates that should be reported as regulatory liabilities. We tested the effectiveness of management's controls over the initial recognition of amounts as regulatory assets or liabilities and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates.

• We obtained and read relevant regulatory orders issued by the BPU and FERC for PSE&G and other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the treatment of similar costs under similar circumstances. We evaluated the external information and compared it to management’s recorded regulatory asset and liability balances for completeness.

• For regulatory matters in process, we inspected associated documents and testimony filed with the BPU or FERC for any evidence that might contradict management's assertions.

• We evaluated the financial statement presentation and disclosures related to the impacts of cost-based rate-regulation, including the balances recorded and regulatory developments.



/s/ DELOITTE & TOUCHE LLP

Morristown, New Jersey
February 26, 2024

We have served as the Company's auditor since 1934.

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PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

CONSOLIDATED STATEMENTS OF OPERATIONS

Millions, except per share data



	Years Ended December 31,
	2023		2022		2021
OPERATING REVENUES	$	11,237	$	9,800	$	9,722
OPERATING EXPENSES
Energy Costs	3,260		4,018		3,499
Operation and Maintenance	3,150		3,178		3,226
Depreciation and Amortization	1,135		1,100		1,216
Losses on Asset Dispositions and Impairments	7		123		2,637
Total Operating Expenses	7,552		8,419		10,578
OPERATING INCOME (LOSS)	3,685		1,381		(856)
Income from Equity Method Investments	1		14		16
Net Gains (Losses) on Trust Investments	189		(265)		194
Net Other Income (Deductions)	172		124		98
Net Non-Operating Pension and Other Postretirement Benefit (OPEB) (Costs) Credits	(218)		376		328
Loss on Extinguishment of Debt	—		—		(298)
Interest Expense	(748)		(628)		(571)
INCOME (LOSS) BEFORE INCOME TAXES	3,081		1,002		(1,089)
Income Tax (Expense) Benefit	(518)		29		441
NET INCOME (LOSS)	$	2,563	$	1,031	$	(648)
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:
BASIC	498		498		504
DILUTED	500		501		504
NET INCOME (LOSS) PER SHARE:
BASIC	$	5.15	$	2.07	$	(1.29)
DILUTED	$	5.13	$	2.06	$	(1.29)

See Notes to Consolidated Financial Statements.

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PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

Millions



	Years Ended December 31,
		2023		2022		2021
NET INCOME (LOSS)		$	2,563	$	1,031	$	(648)
Other Comprehensive Income (Loss), net of tax
Unrealized Gains (Losses) on Available-for-Sale Securities, net of tax (expense) benefit of $(27), $85 and $25 for the years ended 2023, 2022 and 2021, respectively		41		(132)		(39)
Unrealized Gains (Losses) on Cash Flow Hedges, net of tax (expense) benefit of $(2), $(2) and $(1) for the years ended 2023, 2022 and 2021, respectively		6		3		3
Pension/OPEB adjustment, net of tax (expense) benefit of $(127), $28 and $(75) for the years ended 2023, 2022 and 2021, respectively		324		(71)		190
Other Comprehensive Income (Loss), net of tax		371		(200)		154
COMPREHENSIVE INCOME (LOSS)		$	2,934	$	831	$	(494)

See Notes to Consolidated Financial Statements.

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PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

CONSOLIDATED BALANCE SHEETS

Millions



	December 31,
	2023		2022
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents	$	54	$	465
Accounts Receivable, net of allowance of $279 in 2023 and $323 in 2022	1,482		1,944
Tax Receivable	10		79
Unbilled Revenues, net of allowance of $4 in 2023 and $16 in 2022	244		322
Fuel	264		420
Materials and Supplies, net	759		540
Prepayments	144		93
Derivative Contracts	112		18

Regulatory Assets	273		369
Assets Held for Sale	—		20
Other	31		33
Total Current Assets	3,373		4,303
PROPERTY, PLANT AND EQUIPMENT	48,603		45,924
Less: Accumulated Depreciation and Amortization	(10,572)		(9,982)
Net Property, Plant and Equipment	38,031		35,942
NONCURRENT ASSETS
Regulatory Assets	5,157		4,404
Operating Lease Right-of-Use Assets	179		176
Long-Term Investments	295		624
Nuclear Decommissioning Trust (NDT) Fund	2,524		2,230
Long-Term Tax Receivable	—		5
Long-Term Receivable of Variable Interest Entity	632		551
Rabbi Trust Fund	179		183

Derivative Contracts	29		15
Other	342		285
Total Noncurrent Assets	9,337		8,473
TOTAL ASSETS	$	50,741	$	48,718

See Notes to Consolidated Financial Statements.

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PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

CONSOLIDATED BALANCE SHEETS

Millions



	December 31,
	2023		2022
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES
Long-Term Debt Due Within One Year	$	1,500	$	1,575
Commercial Paper and Loans	949		2,200
Accounts Payable	1,214		1,271
Derivative Contracts	86		124
Accrued Interest	170		134
Accrued Taxes	8		12
New Jersey Clean Energy Program	145		145
Obligation to Return Cash Collateral	89		290
Regulatory Liabilities	349		384
Other	547		545
Total Current Liabilities	5,057		6,680
NONCURRENT LIABILITIES
Deferred Income Taxes and Investment Tax Credits (ITC)	6,671		5,725
Regulatory Liabilities	2,075		2,240
Operating Leases	173		169
Asset Retirement Obligations	1,468		1,499
Other Postretirement Benefit (OPEB) Costs	349		410
OPEB Costs of Servco	514		455
Accrued Pension Costs	606		705
Accrued Pension Costs of Servco	102		82

Environmental Costs	213		231
Derivative Contracts	6		33
Long-Term Accrued Taxes	45		66
Other	201		199
Total Noncurrent Liabilities	12,423		11,814
COMMITMENTS AND CONTINGENT LIABILITIES (See Note 13)
CAPITALIZATION
LONG-TERM DEBT	17,784		16,495
STOCKHOLDERS’ EQUITY
Common Stock, no par, authorized 1,000 shares; issued, 2023 and 2022—534 shares	5,018		5,065
Treasury Stock, at cost, 2023 and 2022—36 and 37 shares, respectively	(1,379)		(1,377)
Retained Earnings	12,017		10,591
Accumulated Other Comprehensive Loss	(179)		(550)


Total Stockholders’ Equity	15,477		13,729
Total Capitalization	33,261		30,224
TOTAL LIABILITIES AND CAPITALIZATION	$	50,741	$	48,718

See Notes to Consolidated Financial Statements.

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PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

CONSOLIDATED STATEMENTS OF CASH FLOWS

Millions



	Years Ended December 31,
CASH FLOWS FROM OPERATING ACTIVITIES	2023		2022		2021


Net Income (Loss)	$	2,563	$	1,031	$	(648)
Adjustments to Reconcile Net Income (Loss) to Net Cash Flows from Operating Activities:
Depreciation and Amortization	1,135		1,100		1,216
Amortization of Nuclear Fuel	189		183		187
(Gains) Losses on Asset Dispositions and Impairments	7		123		2,637
Loss on Extinguishment of Debt	—		—		298
Emission Allowances and Renewable Energy Credit (REC) Compliance Accrual	3		55		138
Provision for Deferred Income Taxes and ITC	355		(261)		(845)
Non-Cash Employee Benefit Plan (Credits) Costs	366		(239)		(178)
Net Realized and Unrealized (Gains) Losses on Energy Contracts and Other Derivatives	(1,333)		639		614
Cost of Removal	(166)		(129)		(121)
Energy Efficiency Programs Regulatory Investment Expenditures	(466)		(286)		(117)
Amortization of Energy Efficiency Programs Regulatory Investment Expenditures	82		48		31
Net Change in Other Regulatory Assets and Liabilities	2		(78)		(185)
Net (Gains) Losses and (Income) Expense from NDT Fund	(248)		202		(229)
Net Change in Certain Current Assets and Liabilities:
Cash Collateral	1,408		(677)		(790)
Obligation to Return Cash Collateral	(201)		111		81
Accrued Taxes	(10)		(94)		(127)
Other Current Assets and Liabilities	110		(187)		(263)
Employee Benefit Plan Funding and Related Payments	(40)		(35)		(25)
Other	50		(3)		62
Net Cash Provided By (Used In) Operating Activities	3,806		1,503		1,736
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment	(3,325)		(2,888)		(2,719)
Proceeds from Sales of Trust Investments	1,714		1,586		2,100
Purchases of Trust Investments	(1,751)		(1,611)		(2,092)
Proceeds from Sales of Long-Lived Assets and Lease Investments	37		1,918		569
Proceeds from Sales of Equity Method Investments	291		—		—
Contributions to Equity Method Investments	—		(124)		(111)
Other	76		18		9
Net Cash Provided By (Used In) Investing Activities	(2,958)		(1,101)		(2,244)
CASH FLOWS FROM FINANCING ACTIVITIES
Net Change in Commercial Paper	250		(819)		256
Proceeds from Short-Term Loans	750		2,000		2,500
Repayment of Short-Term Loans	(2,250)		(2,500)		(300)
Issuance of Long-Term Debt	2,800		2,850		2,825
Redemption of Long-Term Debt	(1,575)		(700)		(3,082)
Payments for Share Repurchase Program	—		(500)		—
Premium Paid on Early Extinguishment of Debt	—		—		(294)
Cash Dividends Paid on Common Stock	(1,137)		(1,079)		(1,031)
Other	(98)		(6)		(75)
Net Cash Provided By (Used In) Financing Activities	(1,260)		(754)		799
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash	(412)		(352)		291
Cash, Cash Equivalents and Restricted Cash at Beginning of Period	511		863		572
Cash, Cash Equivalents and Restricted Cash at End of Period	$	99	$	511	$	863
Supplemental Disclosure of Cash Flow Information:
Income Taxes Paid (Received)	$	144	$	353	$	425
Interest Paid, Net of Amounts Capitalized	$	683	$	602	$	547
Accrued Property, Plant and Equipment Expenditures	$	443	$	366	$	331

See Notes to Consolidated Financial Statements.

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PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

Millions



	Common Stock			Treasury Stock			Retained Earnings		Accumulated Other Comprehensive Income (Loss)
	Shs.	Amount		Shs.	Amount						Total
Balance as of December 31, 2020	534	$	5,031	(30)	$	(861)	$	12,318	$	(504)	$	15,984
Net Loss	—	—		—	—		(648)		—		(648)
Other Comprehensive Income (Loss), net of tax (expense) benefit of $(51)	—	—		—	—		—		154		154
Comprehensive Loss											(494)
Cash Dividends at $2.04 per share on Common Stock	—	—		—	—		(1,031)		—		(1,031)
Other	—	14		—	(35)		—		—		(21)
Balance as of December 31, 2021	534	$	5,045	(30)	$	(896)	$	10,639	$	(350)	$	14,438
Net Income	—	—		—	—		1,031		—		1,031
Other Comprehensive Income (Loss), net of tax (expense) benefit of $111	—	—		—	—		—		(200)		(200)
Comprehensive Income											831
Cash Dividends at $2.16 per share on Common Stock	—	—		—			(1,079)		—		(1,079)
Payments for Share Repurchase Program	—	—		(7)	(500)		—		—		(500)
Other	—	20		—	19		—		—		39
Balance as of December 31, 2022	534	$	5,065	(37)	$	(1,377)	$	10,591	$	(550)	$	13,729
Net Income	—	—		—	—		2,563		—		2,563
Other Comprehensive Income (Loss), net of tax (expense) benefit of $(156)	—	—		—	—		—		371		371
Comprehensive Income											2,934

Cash Dividends at $2.28 per share on Common Stock	—	—		—	—		(1,137)		—		(1,137)

Other	—	(47)		1	(2)		—		—		(49)
Balance as of December 31, 2023	534	$	5,018	(36)	$	(1,379)	$	12,017	$	(179)	$	15,477

See Notes to Consolidated Financial Statements.

Table of Conte n t s

PUBLIC SERVICE ELECTRIC AND GAS COMPANY

CONSOLIDATED STATEMENTS OF OPERATIONS

Millions



	Years Ended December 31,
	2023		2022		2021
OPERATING REVENUES	$	7,807	$	7,935	$	7,122
OPERATING EXPENSES
Energy Costs	3,010		3,270		2,688
Operation and Maintenance	1,843		1,838		1,692
Depreciation and Amortization	980		935		928
Gain on Asset Dispositions	—		—		(4)
Total Operating Expenses	5,833		6,043		5,304
OPERATING INCOME	1,974		1,892		1,818
Net Gains (Losses) on Trust Investments	—		(2)		2
Net Other Income (Deductions)	80		88		88
Net Non-Operating Pension and OPEB Credits	114		281		264
Interest Expense	(493)		(427)		(402)
INCOME BEFORE INCOME TAXES	1,675		1,832		1,770
Income Tax Expense	(160)		(267)		(324)
NET INCOME	$	1,515	$	1,565	$	1,446

See disclosures regarding Public Service Electric and Gas Company included in the Notes to Consolidated Financial Statements.

Table of Conte n t s

PUBLIC SERVICE ELECTRIC AND GAS COMPANY

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

Millions



	Years Ended December 31,
		2023		2022		2021
NET INCOME		$	1,515	$	1,565	$	1,446
Other Comprehensive Income (Loss), net of tax
Unrealized Gains (Losses) on Available-for-Sale Securities, net of tax (expense) benefit of $0, $2 and $1 for the years ended 2023, 2022 and 2021, respectively		1		(6)		(2)
COMPREHENSIVE INCOME		$	1,516	$	1,559	$	1,444

See disclosures regarding Public Service Electric and Gas Company included in the Notes to Consolidated Financial Statements.

Table of Conte n t s

PUBLIC SERVICE ELECTRIC AND GAS COMPANY

CONSOLIDATED BALANCE SHEETS

Millions



	December 31,
	2023		2022
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents	$	30	$	220
Accounts Receivable, net of allowance of $279 in 2023 and $323 in 2022	1,076		1,075


Unbilled Revenues, net of allowance of $4 in 2023 and $16 in 2022	244		322
Materials and Supplies, net	519		307
Prepayments	57		7
Regulatory Assets	273		369




Other	31		32
Total Current Assets	2,230		2,332
PROPERTY, PLANT AND EQUIPMENT	43,753		41,045
Less: Accumulated Depreciation and Amortization	(8,711)		(8,215)
Net Property, Plant and Equipment	35,042		32,830
NONCURRENT ASSETS
Regulatory Assets	5,157		4,404
Operating Lease Right-of-Use Assets	99		86
Long-Term Investments	117		143
Rabbi Trust Fund	32		32


Other	196		133
Total Noncurrent Assets	5,601		4,798
TOTAL ASSETS	$	42,873	$	39,960

See disclosures regarding Public Service Electric and Gas Company included in the Notes to Consolidated Financial Statements.

Table of Conte n t s

PUBLIC SERVICE ELECTRIC AND GAS COMPANY

CONSOLIDATED BALANCE SHEETS

Millions



	December 31,
	2023		2022
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES
Long-Term Debt Due Within One Year	$	750	$	825
Commercial Paper and Loans	425		—
Accounts Payable	780		703

Accounts Payable—Affiliated Companies	504		485
Accrued Interest	139		113
New Jersey Clean Energy Program	145		145

Obligation to Return Cash Collateral	89		290
Regulatory Liabilities	349		384
Other	434		416
Total Current Liabilities	3,615		3,361
NONCURRENT LIABILITIES
Deferred Income Taxes and ITC	5,813		5,348
Regulatory Liabilities	2,075		2,240
Operating Leases	89		77
Asset Retirement Obligations	401		384
OPEB Costs	210		255
Accrued Pension Costs	396		397


Environmental Costs	151		173

Long-Term Accrued Taxes	2		9
Other	160		163
Total Noncurrent Liabilities	9,297		9,046
COMMITMENTS AND CONTINGENT LIABILITIES (See Note 13)
CAPITALIZATION
LONG-TERM DEBT	12,913		11,871
STOCKHOLDER’S EQUITY
Common Stock; 150 shares authorized; issued and outstanding, 2023 and 2022—132 shares	892		892
Contributed Capital	2,156		2,156
Retained Earnings	14,004		12,639
Accumulated Other Comprehensive Loss	(4)		(5)
Total Stockholder’s Equity	17,048		15,682
Total Capitalization	29,961		27,553
TOTAL LIABILITIES AND CAPITALIZATION	$	42,873	$	39,960

See disclosures regarding Public Service Electric and Gas Company included in the Notes to Consolidated Financial Statements.

Table of Conte n t s

PUBLIC SERVICE ELECTRIC AND GAS COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

Millions



	Years Ended December 31,
	2023		2022		2021
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	1,515	$	1,565	$	1,446
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	980		935		928

Provision for Deferred Income Taxes and ITC	29		137		116
Non-Cash Employee Benefit Plan (Credits) Costs	8		(179)		(156)
Cost of Removal	(166)		(129)		(121)
Energy Efficiency Programs Regulatory Investment Expenditures	(466)		(286)		(117)
Amortization of Energy Efficiency Programs Regulatory Investment Expenditures	82		48		31
Net Change in Other Regulatory Assets and Liabilities	2		(78)		(185)
Net Change in Certain Current Assets and Liabilities
Accounts Receivable and Unbilled Revenues	72		(132)		(34)
Materials and Supplies	(211)		(73)		(16)
Prepayments	(50)		8		(1)
Accounts Payable	13		96		(71)
Accounts Receivable/Payable—Affiliated Companies, net	(3)		18		(32)
Obligation to Return Cash Collateral	(201)		111		81
Other Current Assets and Liabilities	23		44		(71)
Employee Benefit Plan Funding and Related Payments	(20)		(17)		(10)
Other	(67)		(40)		(64)
Net Cash Provided By (Used In) Operating Activities	1,540		2,028		1,724
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment	(2,998)		(2,590)		(2,447)
Proceeds from Sales of Trust Investments	4		12		35
Purchases of Trust Investments	(3)		(10)		(29)
Solar Loan Investments	27		34		29
Other	6		11		16
Net Cash Provided By (Used In) Investing Activities	(2,964)		(2,543)		(2,396)
CASH FLOWS FROM FINANCING ACTIVITIES
Net Change in Commercial Paper and Loans	425		—		(100)
Issuance of Long-Term Debt	1,800		900		1,325
Redemption of Long-Term Debt	(825)		—		(434)

Cash Dividends Paid	(150)		(450)		—
Other	(17)		(8)		(13)
Net Cash Provided By (Used In) Financing Activities	1,233		442		778
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash	(191)		(73)		106
Cash, Cash Equivalents and Restricted Cash at Beginning of Period	266		339		233
Cash, Cash Equivalents and Restricted Cash at End of Period	$	75	$	266	$	339
Supplemental Disclosure of Cash Flow Information:
Income Taxes Paid (Received)	$	77	$	137	$	266
Interest Paid, Net of Amounts Capitalized	$	449	$	409	$	383
Accrued Property, Plant and Equipment Expenditures	$	395	$	331	$	294

See disclosures regarding Public Service Electric and Gas Company included in the Notes to Consolidated Financial Statements.

Table of Conte n t s

PUBLIC SERVICE ELECTRIC AND GAS COMPANY

CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER’S EQUITY

Millions



	Common Stock		Contributed Capital		Retained Earnings		Accumulated Other Comprehensive Income (Loss)		Total
Balance as of December 31, 2020	$	892	$	2,156	$	10,078	$	3	$	13,129
Net Income	—		—		1,446		—		1,446
Other Comprehensive Income (Loss), net of tax (expense) benefit of $1	—		—		—		(2)		(2)
Comprehensive Income									1,444
Balance as of December 31, 2021	$	892	$	2,156	$	11,524	$	1	$	14,573
Net Income	—		—		1,565		—		1,565
Other Comprehensive Income (Loss), net of tax (expense) benefit of $2	—		—		—		(6)		(6)
Comprehensive Income									1,559
Cash Dividend Paid	$	—	$	—	$	(450)	$	—	(450)
Balance as of December 31, 2022	$	892	$	2,156	$	12,639	$	(5)	$	15,682
Net Income	—		—		1,515		—		1,515
Other Comprehensive Income (Loss), net of tax (expense) benefit of $0	—		—		—		1		1
Comprehensive Income									1,516

Cash Dividends Paid	—		—		(150)		—		(150)

Balance as of December 31, 2023	$	892	$	2,156	$	14,004	$	(4)	$	17,048

See disclosures regarding Public Service Electric and Gas Company included in the Notes to Consolidated Financial Statements.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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Note 1. Organization, Basis of Presentation and Summary of Significant Accounting Policies

Organization

Public Service Enterprise Group Incorporated (PSEG) is a public utility holding company that, acting through its wholly owned subsidiaries, is a predominantly regulated electric and gas utility and a nuclear generation business. PSEG’s principal operating subsidiaries are:

•Public Service Electric and Gas Company (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), the Federal Energy Regulatory Commission (FERC) and other federal and New Jersey state regulators. PSE&G also invests in regulated solar generation projects and energy efficiency (EE) and related programs in New Jersey, which are regulated by the BPU.

•PSEG Power LLC (PSEG Power)—which is an energy supply company that integrates the operations of its merchant nuclear generating assets with its fuel supply functions through competitive energy sales via its principal direct wholly owned subsidiaries. PSEG Power’s subsidiaries are subject to regulation by FERC, the Nuclear Regulatory Commission (NRC), and other federal regulators and state regulators in the states in which they operate.

PSEG’s other direct wholly owned subsidiaries are: PSEG Long Island LLC (PSEG LI), which operates the Long Island Power Authority’s (LIPA) electric transmission and distribution (T&D) system under an Operations Services Agreement (OSA); PSEG Energy Holdings L.L.C. (Energy Holdings), which primarily holds legacy lease investments and competitively bid, FERC regulated transmission; and PSEG Services Corporation (Services), which provides certain management, administrative and general services to PSEG and its subsidiaries at cost.

Basis of Presentation

The respective financial statements included herein have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (SEC) applicable to Annual Reports on Form 10-K and in accordance with accounting guidance generally accepted in the United States (GAAP). Certain reclassifications have been made to prior year financial statements to conform with current year presentation. These reclassifications had no impact on PSEG’s or PSE&G’s results of operations, financial condition or cash flows.

Significant Accounting Policies

Principles of Consolidation

Each company consolidates those entities in which it has a controlling interest or is the primary beneficiary. See Note 4. Variable Interest Entity. Entities over which the companies exhibit significant influence, but do not have a controlling interest and/or are not the primary beneficiary, are accounted for under the equity method of accounting. Equity investments that do not qualify for consolidation or equity method accounting are recorded at fair value or, if fair value is not readily determinable, are initially recognized at cost and subsequently remeasured if there is an orderly transaction in an identical or similar investment of the same issuer or if the investment is impaired. All significant intercompany accounts and transactions are eliminated in consolidation.

PSE&G and PSEG Power also have undivided interests in certain jointly-owned facilities, with each responsible for paying its respective ownership share of construction costs, fuel purchases and operating expenses. PSE&G and PSEG Power consolidate their portion of any revenues and expenses related to their respective jointly-owned facilities in the appropriate revenue and expense categories.

Accounting for the Effects of Regulation

In accordance with accounting guidance for rate-regulated entities, PSE&G’s financial statements reflect the economic effects of regulation. PSE&G defers the recognition of costs (a Regulatory Asset) or records the recognition of obligations (a Regulatory Liability) if it is probable that, through the rate-making process, there will be a corresponding increase or decrease in future rates. Accordingly, PSE&G has deferred certain costs and recoveries, which are being amortized over various future periods. To the extent that collection of any such costs or payment of liabilities becomes no longer probable as a result of changes in regulation, the associated Regulatory Asset or Liability is charged or credited to income. Management believes that PSE&G’s T&D businesses continue to meet the accounting requirements for rate-regulated entities. For additional information, see Note 6. Regulatory Assets and Liabilities.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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Cash, Cash Equivalents and Restricted Cash

The following provides a reconciliation of cash, cash equivalents and restricted cash reported within the Consolidated Balance Sheets that sum to the total of the same such amounts in the Consolidated Statements of Cash Flows for the years ended December 31, 2022 and 2023. Restricted cash consists primarily of deposits received related to a construction project at PSE&G.



	PSE&G		PSEG Power & Other (A)		Consolidated
	Millions
As of December 31, 2022
Cash and Cash Equivalents	$	220	$	245	$	465
Restricted Cash in Other Current Assets	27		—		27
Restricted Cash in Other Noncurrent Assets	19		—		19
Cash, Cash Equivalents and Restricted Cash	$	266	$	245	$	511
As of December 31, 2023
Cash and Cash Equivalents	$	30	$	24	$	54
Restricted Cash in Other Current Assets	23		—		23
Restricted Cash in Other Noncurrent Assets	22		—		22
Cash, Cash Equivalents and Restricted Cash	$	75	$	24	$	99

(A) Includes amounts applicable to PSEG Power, Energy Holdings, Services and PSEG (parent company).

Derivative Instruments

Each company uses derivative instruments to manage risk pursuant to its business plans and prudent practices.

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 to changes in the market price of electricity, 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 and swaps to manage the exposure to fluctuations in commodity prices and optimize the value of PSEG Power’s expected generation. Changes in the fair market value of the derivative contracts are recorded in earnings.

Determining whether a contract qualifies as a derivative requires that management exercise significant judgment, including assessing the contract’s market liquidity. PSEG has determined that contracts to purchase and sell certain products do not meet the definition of a derivative under the current authoritative guidance since they do not provide for net settlement, or the markets are not sufficiently liquid to conclude that physical forward contracts are readily convertible to cash.

Under current authoritative guidance, all derivatives are recognized on the balance sheet at their fair value, except for derivatives that may be designated as normal purchases and normal sales (NPNS). Further, derivatives that qualify for hedge accounting can be designated as fair value or cash flow hedges.

Certain offsetting derivative assets and liabilities 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, these positions are offset on the Consolidated Balance Sheets of PSEG.

For cash flow hedges, the gain or loss on a derivative instrument designated and qualifying as a cash flow hedge is deferred in Accumulated Other Comprehensive Income (Loss) until earnings are affected by the variability of cash flows of the hedged transaction.

For derivative contracts that do not qualify or are not designated as cash flow or fair value hedges or as NPNS, changes in fair value are recorded in current period earnings. PSEG does not currently elect hedge accounting on its commodity derivative positions.

For additional information regarding derivative financial instruments, see Note 16. Financial Risk Management Activities.

Revenue Recognition

PSE&G’s regulated electric and gas revenues are recorded primarily based on services rendered to customers. PSE&G records unbilled revenues for the estimated amount customers will be billed for services rendered from the time meters were last read to the end of the respective accounting period. The unbilled revenue is estimated each month based on usage per day, the number

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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of unbilled days in the period, estimated seasonal loads based upon the time of year and the variance of actual degree-days and temperature-humidity-index hours of the unbilled period from expected norms.

Regulated revenues from the transmission of electricity are recognized as services are provided based on a FERC-approved annual formula rate mechanism. This mechanism provides for an annual filing of estimated revenue requirement with rates effective January 1 of each year. After completion of the annual period ending December 31, PSE&G files a true-up whereby it compares its actual revenue requirement to the original estimate to determine any over or under collection of revenue. PSE&G records the estimated financial statement impact of the difference between the actual and the filed revenue requirement as a refund or deferral for future recovery when such amounts are probable and can be reasonably estimated in accordance with accounting guidance for rate-regulated entities.

PSEG Power currently owns generation within PJM Interconnection, L.L.C. (PJM), which facilitates the dispatch of energy and energy-related products. PSEG generally reports electricity sales and purchases conducted with the PJM Independent System Operator (ISO) at PSEG Power on a net hourly basis in either Revenues or Energy Costs in its Consolidated Statement of Operations, the classification of which depends on the net hourly activity. Capacity revenue and expense are also reported net based on PSEG Power’s monthly net sale or purchase position in PJM. PSEG Power also has revenues that relate to bilateral contracts, which are accounted for on the accrual basis as the energy is delivered. PSEG Power’s revenue also includes changes in the value of energy derivative contracts. See Note 16. Financial Risk Management Activities for further discussion.

PSEG LI is the primary beneficiary of Long Island Electric Utility Servco, LLC (Servco). For transactions in which Servco acts as principal, Servco records revenues and the related pass-through expenditures separately in Operating Revenues and Operation and Maintenance (O&M) Expense, respectively. See Note 4. Variable Interest Entity for further information.

For additional information regarding Revenues, see Note 2. Revenues.

Depreciation and Amortization

PSE&G calculates depreciation under the straight-line method based on estimated average remaining lives of the several classes of property. These estimates are reviewed on a periodic basis and necessary adjustments are made as approved by the BPU or FERC. The average depreciation rate stated as a percentage of original cost of depreciable property was as follows:



	Average Rate
	2023		2022		2021
Electric Transmission	2.09	%	2.18	%	2.29	%
Electric Distribution	2.54	%	2.56	%	2.56	%
Gas Distribution	1.84	%	1.93	%	1.84	%

PSEG calculates depreciation on its nuclear generation-related assets under the straight-line method based on the assets’ estimated useful lives of approximately 60 years to 80 years.

Allowance for Funds Used During Construction (AFUDC) and Interest Capitalized During Construction (IDC)

AFUDC represents the cost of debt and equity funds used to finance the construction of new utility assets at PSE&G. IDC represents the cost of debt used to finance construction at PSEG’s other subsidiaries. The amount of AFUDC or IDC capitalized as Property, Plant and Equipment is included as a reduction of interest charges or other income for the equity portion. The amounts and average rates used to calculate AFUDC or IDC for the years ended December 31, 2023, 2022 and 2021 were as follows:



	AFUDC/IDC Capitalized
	2023				2022				2021
	Millions		Avg Rate		Millions		Avg Rate		Millions		Avg Rate
PSE&G	$	83	7.13	%	$	84	7.39	%	$	93	7.37	%
Other	$	9	5.66	%	$	4	2.24	%	$	9	4.90	%

Income Taxes

PSEG and its subsidiaries file a consolidated federal income tax return and income taxes are allocated to PSEG’s subsidiaries based on the taxable income or loss of each subsidiary on a stand-alone basis in accordance with a tax-sharing agreement between PSEG and each of its affiliated subsidiaries. Allocations between PSEG and its subsidiaries are recorded through intercompany accounts. Investment tax credits (ITC) deferred in prior years are being amortized over the useful lives of the related property.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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Uncertain income tax positions are accounted for using a benefit recognition model with a two-step approach, a more-likely-than-not recognition criterion and a measurement attribute that measures the position as the largest amount of tax benefit that is greater than 50% likely of being realized upon ultimate settlement. If it is not more-likely-than-not that the benefit will be sustained on its technical merits, no benefit will be recorded. Uncertain tax positions that relate only to timing of when an item is included on a tax return are considered to have met the recognition threshold. See Note 20. Income Taxes for further discussion.

Impairment of Long-Lived Assets

Management evaluates long-lived assets for impairment whenever events or changes in circumstances, such as significant adverse changes in regulation, business climate, counterparty credit worthiness or market conditions, including prolonged periods of adverse commodity and capacity prices or a current expectation that a long-lived asset will be sold or disposed of significantly before the end of its previously estimated useful life, could potentially indicate an asset’s or asset group’s carrying amount may not be recoverable. In such an event, an undiscounted cash flow analysis is performed to determine if an impairment exists. When a long-lived asset’s or asset group’s carrying amount exceeds the associated undiscounted estimated future cash flows, the asset/asset group is considered impaired to the extent that its fair value is less than its carrying amount. An impairment would result in a reduction of the value of the long-lived asset/asset group through a non-cash charge to earnings.

For PSEG, cash flows for long-lived assets and asset groups are determined at the lowest level for which identifiable cash flows are largely independent of the cash flows of other assets and liabilities. The cash flows from the nuclear generation units are evaluated at the portfolio level. See Note 3. Asset Dispositions and Impairments for more information on impairment assessments performed on PSEG’s long-lived assets.

Accounts Receivable—Allowance for Credit Losses

PSE&G’s accounts receivable, including unbilled revenues, are primarily comprised of utility customer receivables for the provision of electric and gas service and appliance services, and are reported in 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 coronavirus pandemic on the outstanding balances as of December 31, 2023. PSE&G’s electric bad debt expense is recovered through the Societal Benefits Clause (SBC) mechanism and incremental gas bad debt has been deferred for future recovery through the coronavirus (COVID-19) Regulatory Asset. See Note 2. Revenues and Note 6. Regulatory Assets and Liabilities.

Accounts receivable are charged off in the period in which the receivable is deemed uncollectible. Recoveries of accounts receivable are recorded when it is known they will be received.

Materials and Supplies and Fuel

PSEG and PSE&G’s materials and supplies are carried at average cost and charged to inventory when purchased and expensed or capitalized to Property, Plant and Equipment, as appropriate, when installed or used. Fuel inventory at PSEG is valued at the lower of average cost or market and primarily includes stored natural gas used to satisfy obligations under PSEG Power’s gas supply contracts with PSE&G. The costs of fuel, including initial transportation costs, are included in inventory when purchased and charged to Energy Costs when used or sold. The cost of nuclear fuel is capitalized within Property, Plant and Equipment and amortized to fuel expense using the units-of-production method.

Property, Plant and Equipment

PSE&G’s additions to and replacements of existing property, plant and equipment are capitalized at cost. The cost of maintenance, repair and replacement of minor items of property is charged to expense as incurred. At the time units of depreciable property are retired or otherwise disposed of, the original cost, adjusted for net salvage value, is charged to accumulated depreciation.

PSEG capitalizes costs related to its generating assets, including those related to its jointly-owned facilities that increase the capacity, improve or extend the life of an existing asset; represent a newly acquired or constructed asset; or represent the replacement of a retired asset. The cost of maintenance, repair and replacement of minor items of property is charged to appropriate expense accounts as incurred. Environmental costs are capitalized if the costs mitigate or prevent future environmental contamination or if the costs improve existing assets’ environmental safety or efficiency. All other environmental expenditures are expensed as incurred. PSEG also capitalizes spare parts for its generating assets that meet specific criteria. Capitalized spare parts are depreciated over the remaining lives of their associated assets.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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Leases

PSEG and its subsidiaries, when acting as lessee or lessor, determine if an arrangement is a lease at inception. PSEG assesses contracts to determine if the arrangement conveys (i) the right to control the use of the identified property, (ii) the right to obtain substantially all of the economic benefits from the use of the property, and (iii) the right to direct the use of the property.

PSEG and its subsidiaries are neither the lessee nor the lessor in any material leases that are not classified as operating leases.

Lessee—Operating Lease Right-of-Use Assets represent the right to use an underlying asset for the lease term and Operating Lease Liabilities represent the obligation to make lease payments arising from the lease. Operating Lease Right-of-Use Assets and Operating Lease Liabilities are recognized at the lease commencement date based on the present value of lease payments over the lease term.

The current portion of Operating Lease Liabilities is included in Other Current Liabilities. Operating Lease Right-of-Use Assets and noncurrent Operating Lease Liabilities are included as separate captions in Noncurrent Assets and Noncurrent Liabilities, respectively, on the Consolidated Balance Sheets of PSEG and PSE&G. PSEG and its subsidiaries do not recognize Operating Lease Right-of-Use Assets and Operating Lease Liabilities for leases where the term is twelve months or less.

PSEG and its subsidiaries recognize the lease payments on a straight-line basis over the term of the leases and variable lease payments in the period in which the obligations for those payments are incurred.

As lessee, most of the operating leases of PSEG and its subsidiaries do not provide an implicit rate; therefore, incremental borrowing rates are used based on the information available at commencement date in determining the present value of lease payments. The implicit rate is used when readily determinable. PSE&G’s incremental borrowing rates are based on secured borrowing rates. PSEG’s incremental borrowing rates are generally unsecured rates. Having calculated simulated secured rates for each of PSEG and PSEG Power, it was determined that the difference between the unsecured borrowing rates and the simulated secured rates had an immaterial effect on their recorded Operating Lease Right-of-Use Assets and Operating Lease Liabilities. Services, PSEG LI and other subsidiaries of PSEG that do not borrow funds or issue debt may enter into leases. Since these companies do not have credit ratings and related incremental borrowing rates, PSEG has determined that it is appropriate for these companies to use the incremental borrowing rate of PSEG, the parent company.

Lease terms may include options to extend or terminate the lease when it is reasonably certain that such options will be exercised.

PSEG and its subsidiaries have lease agreements with lease and non-lease components. For real estate, equipment and vehicle leases, the lease and non-lease components are accounted for as a single lease component.

Lessor—Property subject to operating leases, where PSEG or one of its subsidiaries is the lessor, is included in Property, Plant and Equipment and rental income from these leases is included in Operating Revenues.

PSEG and its subsidiaries have lease agreements with lease and non-lease components, which are primarily related to domestic energy generation. PSEG and subsidiaries account for the lease and non-lease components as a single lease component. See Note 7. Leases for detailed information on leases.

Energy Holdings is the lessor in leveraged leases. Leveraged lease accounting guidance is grandfathered for existing leveraged leases. Energy Holdings’ leveraged leases are accounted for in Operating Revenues and in Noncurrent Long-Term Investments. If modified after January 1, 2019, those leveraged leases will be accounted for as operating or financing leases. See Note 8. Long-Term Investments and Note 9. Financing Receivables.

Trust Investments

These securities comprise the Nuclear Decommissioning Trust (NDT) Fund, a master independent external trust account maintained to provide for the costs of decommissioning upon termination of operations of PSEG’s nuclear facilities and amounts that are deposited to fund a Rabbi Trust which was established to meet the obligations related to non-qualified pension plans and deferred compensation plans.

Unrealized gains and losses on equity security investments are recorded in Net Income. The debt securities are classified as available-for-sale with the unrealized gains and losses recorded as a component of Accumulated Other Comprehensive Income (Loss). Realized gains and losses on both equity and available-for-sale debt security investments are recorded in earnings and are included with the unrealized gains and losses on equity securities in Net Gains (Losses) on Trust Investments. Other-than-temporary impairments on NDT and Rabbi Trust debt securities are also included in Net Gains (Losses) on Trust Investments. See Note 10. Trust Investments for further discussion.

Pension and Other Postretirement Benefits (OPEB) Plans

The market-related value of plan assets held for the qualified pension and OPEB plans is equal to the fair value of those assets as of year-end. Fair value is determined using quoted market prices and independent pricing services based upon the security

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type as reported by the trustee at the measurement date (December 31) as well as investments in unlisted real estate which are valued via third-party appraisals.

PSEG recognizes a long-term receivable primarily related to future funding by LIPA of Servco’s recognized pension and OPEB liabilities. This receivable is presented separately on the Consolidated Balance Sheet of PSEG as a noncurrent asset. Pursuant to the OSA, Servco records expense for contributions to its pension plan trusts and for OPEB payments made to retirees.

See Note 12. Pension, Other Postretirement Benefits (OPEB) and Savings Plans for further discussion.

Basis Adjustment

PSE&G has recorded a Basis Adjustment in its Consolidated Balance Sheet related to the generation assets that were transferred from PSE&G to PSEG Power in August 2000 at the price specified by the BPU. Because the transfer was between affiliates, the transaction was recorded at the net book value of the assets and liabilities rather than the transfer price. The difference between the total transfer price and the net book value of the generation-related assets and liabilities, $986 million, net of tax, was recorded as a Basis Adjustment on PSE&G’s and PSEG Power’s Consolidated Balance Sheets. The $986 million is an addition to PSE&G’s Common Stockholder’s Equity and a reduction of PSEG Power’s Member’s Equity. These amounts are eliminated on PSEG’s consolidated financial statements.

On December 31, 2023, PSE&G reclassified certain stockholder’s equity amounts on its Consolidated Balance Sheets and Consolidated Statements of Common Stockholder's Equity. The previously disclosed Basis Adjustment amount of $986 million was combined with Contributed Capital, based on the underlying nature of the Basis Adjustment. This reclassification had no impact on previously reported total stockholder's equity amounts.

Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Recent Accounting Standards

Improvements to Reportable Segment Disclosures—Accounting Standards Update (ASU) 2023-07

This ASU requires disclosure of incremental segment information, including additional detail on certain significant segment expenses, on an annual and interim basis to enable investors to develop more decision-useful financial analyses. The ASU is effective for fiscal years beginning after December 15, 2023 and interim periods beginning after December 15, 2024. PSEG and PSE&G are currently analyzing the impact of this standard on their future disclosures.

Improvements to Income Tax Disclosures—ASU 2023-09

This ASU makes amendments to the current reconciliation disclosure to improve transparency by requiring consistent categories and greater jurisdictional disaggregation. The ASU also provides for the inclusion of an income taxes paid disclosure by jurisdiction. The ASU is effective for annual periods beginning after December 15, 2024. PSEG and PSE&G are currently analyzing the impact of this ASU on their future disclosures.

Note 2. Revenues

Nature of Goods and Services

The following is a description of principal activities by which PSEG and its subsidiaries generate their revenues.

PSE&G

Revenues from Contracts with Customers

Electric and Gas Distribution and Transmission Revenues—PSE&G sells gas and electricity to customers under default commodity supply tariffs. PSE&G’s regulated electric and gas default commodity supply and distribution services are separate tariffs which are satisfied as the product(s) and/or service(s) are delivered to the customer. The electric and gas commodity and delivery tariffs are recurring contracts in effect until modified through the regulatory approval process as appropriate. Revenue is recognized over time as the service is rendered to the customer. Included in PSE&G’s regulated revenues are unbilled electric and gas revenues which represent the estimated amount customers will be billed for services rendered from the most recent meter reading to the end of the respective accounting period.

PSE&G’s transmission revenues are earned under a separate tariff using a FERC-approved annual formula rate mechanism. The performance obligation of transmission service is satisfied and revenue is recognized as it is provided to the customer. The formula rate mechanism provides for an annual filing of an estimated revenue requirement with rates effective January 1 of

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each year and a true-up to that estimate based on actual revenue requirements. The true-up mechanism is an alternative revenue which is outside the scope of revenue from contracts with customers.

Other Revenues from Contracts with Customers

Other revenues from contracts with customers, which are not a material source of PSE&G revenues, are generated primarily from appliance repair services and solar generation projects. The performance obligations under these contracts are satisfied and revenue is recognized as control of products is delivered or services are rendered.

Revenues Unrelated to Contracts with Customers

Other PSE&G revenues unrelated to contracts with customers are derived from alternative revenue mechanisms recorded pursuant to regulatory accounting guidance. These revenues, which include the Conservation Incentive Program (CIP), green energy program true-ups and transmission formula rate true-ups, are not a material source of PSE&G revenues.

PSEG Power & Other

Revenues from Contracts with Customers

Electricity and Related Products—PSEG Power owns generation solely within PJM, which facilitates the dispatch of energy and energy-related products. Prior to the sale of the fossil generation assets in 2022, PSEG Power also had significant sales in the New York Independent System Operator (NYISO) and the New England Independent System Operator (ISO-NE) regions.

PSEG Power primarily sells to the PJM ISO 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 PJM 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 bundled service is provided to the customer. PSEG generally reports electricity sales and purchases conducted with PJM net on an hourly basis in either Operating Revenues or Energy Costs in its Consolidated Statements of Operations. The classification depends on the net hourly activity.

PSEG Power enters into capacity sales and capacity purchases through PJM. The transactions are reported on a net basis dependent on PSEG Power’s monthly net sale or purchase position through PJM. The performance obligations with PJM are satisfied over time upon delivery of the capacity and revenue is recognized accordingly. In addition to capacity sold through PJM, 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 late December 2022, PJM called its first ISO-wide Maximum Generation Emergency Action as a result of Winter Storm Elliott, 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 estimated impact of Salem 2’s penalties and bonuses earned by the other units was not material to PSEG’s financial results in 2022 or 2023.

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. The number of ZECs purchased by each EDC from a selected nuclear power plant for an energy year is expected to be reduced by the number of ZECs equal in value to the dollar amount of production tax credits (PTCs) received by the same plants. In May 2021, the New Jersey Rate Counsel filed an appeal with the New Jersey Appellate Division of the BPU’s decision in 2021 to award ZECs to the nuclear plants. In December 2023, the Appellate Division rejected Rate Counsel’s appeal and affirmed the BPU’s April 2021 decision and the period during which Rate Counsel could appeal the Appellate Division decision to the New Jersey Supreme Court has expired. No further appeals are permitted.

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 PSE&G’s customers. The BGSS contract remains in effect unless terminated by either party with a 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 performance obligation is primarily the delivery of gas which is satisfied over time. Revenue is recognized as gas is delivered or pipeline capacity is released.

PSEG LI Contract—PSEG LI has a contract with LIPA which generates revenues. PSEG LI’s subsidiary, Servco records costs which are recovered from LIPA and records the recovery of those costs as revenues when Servco is a principal in the transaction.

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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 recognized over time as services are rendered.

Revenues Unrelated to Contracts with Customers

PSEG Power’s revenues unrelated to contracts with customers include electric, gas and certain energy-related transactions accounted for in accordance with Derivatives and Hedging accounting guidance. See Note 16. Financial Risk Management Activities for further discussion.

Energy Holdings generates lease revenues which are recorded pursuant to lease accounting guidance.

Disaggregation of Revenues



	PSE&G		PSEG Power & Other (A)		Eliminations		Consolidated
	Millions
Year Ended December 31, 2023
Revenues from Contracts with Customers
Electric Distribution	$	3,494	$	—	$	—	$	3,494
Gas Distribution	1,982		—		—		1,982
Transmission	1,673		—		—		1,673
Electricity and Related Product Sales
PJM
Third-Party Sales	—		892		—		892
Sales to Affiliates	—		114		(114)		—

ISO-NE	—		13		—		13
Gas Sales
Third-Party Sales	—		206		—		206
Sales to Affiliates	—		984		(984)		—
Other Revenues from Contracts with Customers (B)	368		631		(5)		994
Total Revenues from Contracts with Customers	7,517		2,840		(1,103)		9,254
Revenues Unrelated to Contracts with Customers (C)	290		1,693		—		1,983
Total Operating Revenues	$	7,807	$	4,533	$	(1,103)	$	11,237



	PSE&G		PSEG Power & Other (A)		Eliminations		Consolidated
	Millions
Year Ended December 31, 2022
Revenues from Contracts with Customers
Electric Distribution	$	3,503	$	—	$	—	$	3,503
Gas Distribution	2,357		—		(1)		2,356
Transmission	1,589		—		—		1,589
Electricity and Related Product Sales
PJM
Third-Party Sales	—		2,152		—		2,152
Sales to Affiliates	—		151		(151)		—
NYISO	—		88		—		88
ISO-NE	—		96		—		96
Gas Sales
Third-Party Sales	—		458		—		458
Sales to Affiliates	—		1,243		(1,243)		—
Other Revenues from Contracts with Customers (B)	390		605		(6)		989
Total Revenues from Contracts with Customers	7,839		4,793		(1,401)		11,231
Revenues Unrelated to Contracts with Customers (C)	96		(1,527)		—		(1,431)
Total Operating Revenues	$	7,935	$	3,266	$	(1,401)	$	9,800

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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	PSE&G		PSEG Power & Other (A)		Eliminations		Consolidated
	Millions
Year Ended December 31, 2021
Revenues from Contracts with Customers
Electric Distribution	$	3,279	$	—	$	—	$	3,279
Gas Distribution	1,875		—		(13)		1,862
Transmission	1,611		—		—		1,611
Electricity and Related Product Sales
PJM
Third-Party Sales	—		2,003		—		2,003
Sales to Affiliates	—		265		(265)		—
NYISO	—		247		—		247
ISO-NE	—		172		—		172
Gas Sales
Third-Party Sales	—		181		—		181
Sales to Affiliates	—		886		(886)		—
Other Revenues from Contracts with Customers (B)	343		620		(3)		960
Total Revenues from Contracts with Customers	7,108		4,374		(1,167)		10,315
Revenues Unrelated to Contracts with Customers (C)	14		(607)		—		(593)
Total Operating Revenues	$	7,122	$	3,767	$	(1,167)	$	9,722

(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 Power’s energy management fee with LIPA and PSEG LI’s OSA with LIPA.

(C)Includes primarily alternative revenues at PSE&G principally from the CIP program in 2022 and 2023 and net realized and unrealized gains (losses) on derivative contracts and lease contracts at PSEG Power & Other.

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 December 31, 2023 and 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 18% and 20% of accounts receivable (including unbilled revenues) as of December 31, 2023 and 2022, respectively.

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 December 31, 2023. PSE&G’s electric bad debt expense is recoverable through its SBC mechanism. As of December 31, 2023, PSE&G had a deferred balance of $149 million from electric bad debts recorded as a Regulatory Asset. In addition, as of December 31, 2023, PSE&G had deferred incremental gas bad debt expense of $68 million recorded as a Regulatory Asset for future regulatory recovery due to the impact of the coronavirus pandemic. See Note 6. Regulatory Assets and Liabilities for additional information.

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The following provides a reconciliation of PSE&G’s allowance for credit losses for the years ended December 31, 2023 and 2022.










	Years Ended December 31,
	2023		2022
	Millions
Balance at Beginning of Year	$	339	$	337
Utility Customer and Other Accounts
Provision	100		114
Write-offs, net of Recoveries of $25 million and $46 million for 2023 and 2022, respectively	(156)		(112)
Balance at End of Year	$	283	$	339

PSEG Power & Other

PSEG Power generally collects consideration upon satisfaction of performance obligations, and therefore, PSEG Power had no material contract balances as of December 31, 2023 and 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 Consolidated Balance Sheets.

PSEG Power’s accounts receivable consist mainly of revenues from energy and ancillary services sold directly to ISOs and other counterparties. In the wholesale energy markets in which PSEG Power 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 December 31, 2023 and 2022. PSEG Power monitors the status of 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 December 31, 2023 and 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 a customer in an amount that corresponds directly with the value to the 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 Power’s monthly net sale or purchase position.

Amended OSA—In April 2022, PSEG LI entered into an amended OSA with LIPA. 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 2024 is approximately $44 million and is updated each year based on the change in the Consumer Price Index (CPI).

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Note 3. Asset Dispositions and Impairments

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 July 2023, PSEG Power completed the sale of its 50% ownership interest in Kalaeloa. The sale proceeds approximated PSEG Power's carrying value of the investment; therefore, no material gain or loss was recognized upon disposition.

In 2022, Energy Holdings recorded pre-tax impairments of $78 million related to one of its domestic energy generating facilities and its real estate assets. In March 2023, Energy Holdings completed the sale of its domestic energy generating facility and recorded an immaterial pre-tax gain. In December 2023, Energy Holdings completed the sale of its real estate assets and recorded an immaterial pre-tax gain.

In August 2021, PSEG entered into two agreements to sell PSEG Power’s 6,750 MW fossil generating portfolio, one agreement for the sale of assets in New Jersey and Maryland and another agreement for the sale of assets located in New York and Connecticut, to newly formed subsidiaries of ArcLight Energy Partners Fund VII, L.P., a fund controlled by ArcLight Capital Partners, LLC for aggregate consideration of approximately $1,920 million. In 2021, PSEG recorded a pre-tax impairment loss on sale of approximately $2,691 million as the purchase price was lower than the carrying value in 2021. In addition to the impairment loss, all of PSEG Power’s outstanding debt obligations were redeemed and PSEG incurred a pre-tax loss of $298 million for the make-whole provision payable upon early redemption and other non-cash debt extinguishment costs and also recorded approximately $13 million in pre-tax severance and retention charges, environmental accruals and other adjustments.

As defined in each agreement, further adjustments were required as a result of any purchase price or 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 closing dates. As a result, in 2022 PSEG Power recorded an additional pre-tax impairment of approximately $50 million prior to completing the sale of this fossil generating portfolio in February 2022.

PSEG Power has retained ownership of certain liabilities excluded from the transactions primarily related to obligations under certain environmental regulations, including 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 in the aggregate.

In May 2021, PSEG Power Ventures LLC (Power Ventures), a direct wholly owned subsidiary of PSEG Power, entered into a purchase agreement with Quattro Solar, LLC, an affiliate of LS Power, relating to the sale by Power Ventures of 100% of its ownership interest in PSEG Solar Source LLC (Solar Source) including its related assets and liabilities. The transaction closed in June 2021. As a result of the sale, PSEG Power recorded a pre-tax gain on sale of approximately $63 million, which is inclusive of the recognition of previously deferred unamortized ITCs of $185 million, and income tax expense of approximately $62 million primarily due to the recapture of ITC on units that operated for less than five years.

Note 4. Variable Interest Entity (VIE)

VIE for which PSEG LI is the Primary Beneficiary

PSEG LI consolidates 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 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 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 Expense, respectively. In 2023, 2022 and 2021, Servco recorded $533 million, $516 million and $511 million, respectively, of O&M costs, the full reimbursement of

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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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 Consolidated Statement of Operations.

Note 5. Property, Plant and Equipment and Jointly-Owned Facilities

Information related to Property, Plant and Equipment as of December 31, 2023 and 2022 is detailed below:



	2023		2022
	Millions
PSE&G
Electric Transmission	$	17,379	$	16,393
Electric Distribution	11,554		10,785
Gas Distribution and Transmission	11,545		10,616
Construction Work in Progress	1,283		1,336
Other	1,992		1,915
Total PSE&G	43,753		41,045
Nuclear Production	3,496		3,567
Nuclear Fuel in Service	772		758
Construction Work in Progress	224		177
Other	358		377
Total	$	48,603	$	45,924

PSE&G and PSEG Power have ownership interests in and are responsible for providing their respective shares of the necessary financing for the following jointly-owned facilities to which they are a party. All amounts reflect PSE&G’s or PSEG Power’s share of the jointly-owned projects and the corresponding direct expenses are included in the Consolidated Statements of Operations as Operating Expenses.



			As of December 31,
			2023				2022
	Ownership				Accumulated				Accumulated
	Interest		Plant		Depreciation		Plant		Depreciation
			Millions
PSE&G:
Transmission Facilities	Various		$	164	$	69	$	164	$	67
PSEG Power:
Nuclear Generating:
Peach Bottom	50	%	$	1,451	$	534	$	1,444	$	506
Salem	57	%	$	1,461	$	534	$	1,455	$	516
Nuclear Support Facilities	Various		$	178	$	77	$	228	$	119
Other	14	%	$	1	$	—	$	1	$	—

PSEG Power holds undivided ownership interests in the jointly-owned facilities above. PSEG Power is entitled to shares of the generating capability and output of each unit equal to its respective ownership interests. PSEG Power also pays its ownership share of additional construction costs, fuel inventory purchases and operating expenses. PSEG Power’s share of expenses for the jointly-owned facilities is included in the appropriate expense category. Each owner is responsible for any financing with respect to its pro rata share of capital expenditures.

PSEG Power co-owns Salem and Peach Bottom with Constellation Energy Generation, LLC. PSEG Power is the operator of Salem and Constellation Energy Generation, LLC is the operator of Peach Bottom. A committee appointed by the co-owners provides oversight. Proposed O&M budgets and requests for major capital expenditures are reviewed and approved as part of the normal PSEG Power governance process.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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Note 6. Regulatory Assets and Liabilities

PSE&G prepares its financial statements in accordance with GAAP for regulated utilities as described in Note 1. Organization, Basis of Presentation and Summary of Significant Accounting Policies. PSE&G has deferred certain costs based on rate orders issued by the BPU or FERC or based on PSE&G’s experience with prior rate proceedings. Most of PSE&G’s Regulatory Assets and Liabilities as of December 31, 2023 are supported by written orders, either explicitly or implicitly through the BPU’s treatment of various cost items. These costs will be recovered and amortized over various future periods.

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

PSE&G had the following Regulatory Assets and Liabilities:



	As of December 31,
	2023		2022
	Millions
Regulatory Assets
Current
New Jersey Clean Energy Program	$	145	$	145
Conservation Incentive Program (CIP)	103		51
Electric Energy Costs—Basic Generation Service (BGS)	19		54
Societal Benefits Clause (SBC)	6		20
Tax Adjustment Credit (TAC)	—		52

2018 Distribution Base Rate Case Regulatory Assets (BRC)	—		47



Total Current Regulatory Assets	273		369
Noncurrent
Pension and OPEB Costs	$	1,427	$	1,405
Deferred Income Tax Regulatory Assets	1,343		1,168
Green Program Recovery Charges (GPRC)	827		447
Asset Retirement Obligations (ARO)	210		200
Manufactured Gas Plant (MGP) Remediation Costs	199		206
Cost of Removal	172		156
Clean Energy Future-Energy Cloud (CEF-EC) (Advanced Metering Infrastructure (AMI))	153		80
SBC (Electric Bad Debt)	149		145
COVID-19 Deferral	131		137
CIP	129		72
Remediation Adjustment Charge (RAC) (Other SBC)	110		134
Deferred Storm Costs	109		109
Other	198		145
Total Noncurrent Regulatory Assets	5,157		4,404
Total Regulatory Assets	$	5,430	$	4,773

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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	As of December 31,
	2023		2022
	Millions
Regulatory Liabilities
Current
Deferred Income Tax Regulatory Liabilities	$	170	$	302

Gas Costs—Basic Gas Supply Service (BGSS)	97		35
Formula Rate True-up	22		1
GPRC	20		24

TAC	18		—
Other	22		22
Total Current Regulatory Liabilities	349		384
Noncurrent
Deferred Income Tax Regulatory Liabilities	$	2,075	$	2,196
Formula Rate True-up	—		31

Other	—		13
Total Noncurrent Regulatory Liabilities	2,075		2,240
Total Regulatory Liabilities	$	2,424	$	2,624

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

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

•BRC: Represents deferred costs, primarily comprised of storm costs incurred in the cleanup of major storms from 2010 through 2018, which are being amortized over five years pursuant to the 2018 Distribution Base Rate Case Settlement. These costs were fully recovered as of December 31, 2023.

•CEF-EC (AMI Initiative): In January 2021, the BPU approved PSE&G’s CEF-EC filing to provide its electric customers with smart meters. All of the capital and operating costs of the program are included for recovery in PSE&G’s recently filed distribution base rate case. From the start of the program until the commencement of new base rates, the return on and of the capital portion of the program is included for recovery in those rates, as well as operating and stranded costs associated with the accelerated retirement of the existing non-AMI electric meters which PSE&G expects to conclude by the end of 2024.

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

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

•COVID-19 Deferral: These amounts represent incremental costs related to COVID-19 as authorized for deferral in an order issued by the BPU to all New Jersey regulated utilities in July 2020. The BPU authorized such utilities to create a COVID-19-related Regulatory Asset by deferring on their books and records the prudently incurred incremental costs related to COVID-19 during the Regulatory Asset period as defined by the BPU. Deferred costs are to be offset by any federal or state assistance that the utility may receive as a direct result of the COVID-19 pandemic. Utilities must file quarterly reports of the costs incurred and offsets. As directed by the BPU, in July 2023, PSE&G filed a petition documenting its prudently incurred incremental COVID-19 costs. Rate recovery, including any prudency determinations and the appropriate period of recovery, will be addressed through that filing which is currently pending.

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•Deferred Income Tax Regulatory Assets: These amounts relate to deferred income taxes arising from utility operations that have not been included in customer rates relating to depreciation, ITCs and other flow-through items, including the flowback to customers of accumulated deferred income taxes related to tax repair deductions. As part of its distribution base rate case settlement with the BPU and the establishment of the TAC mechanism in 2018, PSE&G agreed to a ten-year flowback to customers of its accumulated deferred income taxes from previously realized tax repair deductions which resulted in the recognition of a $581 million Regulatory Asset and Regulatory Liability as of September 30, 2018. In addition, PSE&G agreed to the current flowback of tax benefits from ongoing tax repair deductions as realized which results in the recording of a Regulatory Asset upon flowback. For the years ended December 31, 2023, 2022 and 2021, PSE&G had provided $80 million, $35 million and $22 million, respectively, in current tax repair flowbacks to customers. The recovery and amortization of the tax repair-related Deferred Income Tax Regulatory Assets is being recovered through the TAC regulatory mechanism.

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

•Unprotected distribution-related excess deferred income taxes are being refunded to customers over five years through PSE&G’s TAC mechanism as approved in its 2018 distribution base rate proceeding. As of December 31, 2023, the balance remaining to be flowed back to customers was approximately $20 million with the remaining flowback period through 2024.

•Protected distribution-related excess deferred income taxes are being refunded to customers over the remaining useful lives of distribution property, plant and equipment through PSE&G’s TAC mechanism. As of December 31, 2023, the balance remaining to be flowed back to customers was approximately $862 million.

•Previously realized distribution-related tax repair deductions are being refunded to customers over ten years through PSE&G’s TAC mechanism. As of December 31, 2023, the balance remaining to be flowed back to customers was approximately $387 million through 2028.

•Protected transmission-related excess deferred income taxes are being refunded to customers over the remaining useful life of transmission property, plant and equipment through PSE&G’s transmission formula rate mechanism. As of December 31, 2023, the balance remaining to be flowed back to customers was approximately $931 million.

•Deferred Storm Costs: Incremental costs incurred in the restoration and related costs from major storms from 2019 through 2022 for which PSE&G is seeking recovery in its current distribution base rate proceeding.

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

•Formula Rate True-Up: PSE&G’s transmission revenues are earned under a FERC-approved annual formula rate mechanism which provides for an annual filing of an estimated revenue requirement with rates effective January 1 of each year and a true-up to that estimate based on actual revenue requirements.

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

•GPRC: PSE&G files an annual GPRC petition with the BPU for recovery of amounts associated with the BPU Board-approved energy efficiency (EE) and solar (renewable) energy (RE) programs that include a return on and of investments and capital assets, as well as recovery for deferred expenses and incremental costs. The GPRC

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investment program component is recovered over the lives of the underlying investments and capital assets which range from five to twenty years.

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

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

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

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

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

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

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

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

•TAC: This represents the over or under collected electric and gas balances associated with the return of excess accumulated deferred income taxes and the flowback of previously realized and current tax repair deductions under a mechanism approved by the BPU in PSE&G’s 2018 Distribution Base Rate Case Settlement. Over or under collected electric and gas balances are returned or recovered through an annual filing. PSE&G includes a return component on the flowback of the excess accumulated deferred income taxes and the previously realized tax repairs. Interest is accrued monthly on any over or under recovered balances.

Significant 2023 regulatory orders received and currently pending rate filings with the BPU or FERC by PSE&G are as follows:

•Electric and Gas Distribution Base Rate Filing—In December 2023, PSE&G filed a distribution base rate case as required as a condition of approval of previous PSE&G programs. This distribution base rate case requests an overall revenue increase of approximately $826 million which includes the recovery of approximately $3 billion in capital investments made by PSE&G to strengthen and modernize its electric and gas infrastructure since its last distribution base rate case in 2018. PSE&G anticipates this base rate case will be finalized later in 2024.

•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 September 2023, the BPU approved on a provisional basis PSE&G’s June 2023 request to decrease its BGSS rate to approximately 40 cents per therm, effective October 1, 2023.

The BGSS rate has decreased a total of 25 cents from approximately 65 cents per therm as of January 1, 2023 to 40 cents per therm as of October 1, 2023.

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•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.

In September 2023, the BPU provisionally approved PSE&G’s gas CIP petition to recover $110 million of deficient gas revenues comprised of approximately $99 million for the most recent gas CIP annual period ended September 30, 2023, and an additional $11 million carryover underrecovery from the prior CIP period. The revenue deficiency is the result of lower revenues as compared to a baseline established in PSE&G’s most recent distribution base rate proceeding. New rates were effective October 1, 2023 and PSE&G expects to recover the full $110 million deficiency over a 12-month period.

In December 2023, the BPU gave final approval for PSE&G’s updated electric CIP petition to recover approximately $75 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 February 2024, PSE&G filed its annual electric CIP petition seeking BPU approval to recover estimated deficient electric revenues of approximately $99 million based on the 12-month period ending May 31, 2024 with new rates proposed to be effective June 1, 2024. 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 prudently incurred incremental costs associated with the COVID-19 pandemic. This matter is pending.

As of December 31, 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 October 2023, the BPU approved PSE&G’s updated filing for an annual increase in electric revenues of approximately $9 million associated with capitalized electric investment costs of the Energy Strong II program, with new rates effective November 1, 2023. This increase represents the return on and of actual investments through July 31, 2023.

In February 2024, PSE&G filed an updated petition seeking BPU approval to recover an annualized increase in electric revenue requirement of $13 million associated with capitalized investment costs of the Energy Strong II Program, with rates to be effective May 1, 2024. The requested electric revenue increase represents the return of and on actual Energy Strong II investments placed in service through December 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.

•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 CEF-EE sub program investment (a component of GPRC) by $280 million and approved a nine-month extension to make investments.

In February 2024, PSE&G updated its 2023 GPRC cost recovery petition requesting BPU approval for recovery of increases of $49 million and $15 million in annual electric and gas revenues, respectively. This matter is pending.

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

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•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 December 31, 2023, PSE&G has deferred $55 million as a Regulatory Asset under this methodology.

•RAC—In January 2023, PSE&G filed its RAC 30 petition with the BPU seeking recovery of approximately $44 million of net 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 RE 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.

•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.

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

•Transmission Formula Rates—In June 2023, PSE&G filed with FERC its 2022 true-up adjustment pertaining to its transmission formula rates in effect for calendar year 2022, as established by its 2022 annual forecast filing. The June 2023 true-up filing resulted in an approximate $21 million decrease in the 2022 annual revenue requirement from the revenue requirement numbers contained in the forecast filing. PSE&G had previously recognized the majority of the lower revenue requirement in its 2022 Consolidated Statement of Operations.

In October 2023, PSE&G filed its Annual Transmission Formula Rate Update with FERC, which will result in a $58 million increase in annual transmission revenue effective January 1, 2024, subject to true-up.

•ZEC Program—In January 2023, the BPU approved PSE&G’s petition to set the ZEC refund component of the tariff rate to zero effective February 1, 2023 as overcollections for the ZEC Energy Year ended May 31, 2022 totaling $1.3 million, including interest, were refunded to customers in 2022 through January 2023.

In August 2023, the BPU approved the final ZEC price of $9.88 per megawatt hour (MWh) for the energy year ended May 31, 2023. As a result, PSE&G purchased approximately $165 million in ZECs including interest, from the eligible nuclear plants selected by the BPU with the final payment made in August 2023. As total customer collections equaled the required ZEC payments, there were no overcollected revenues from customers for the Energy Year ended May 31, 2023 and the ZEC refund component of the rate remains at zero.

Note 7. Leases

As of December 31, 2023, PSEG and its subsidiaries were both a lessee and a lessor in operating leases.

Lessee

PSE&G

PSE&G has operating leases for office space for customer service centers, rooftops and land for its Solar 4 All® facilities, equipment, vehicles and land for certain electric substations. These leases have remaining lease terms through 2040, some of which include options to extend the leases for up to four 5-year terms or one 10-year term; and two include options to extend the leases for one 45-year and one 48-year term, respectively. Some leases have fixed rent payments that have escalations based on certain indices, such as the CPI. Certain leases contain variable payments.

PSEG Power & Other

PSEG Power has operating leases for buildings and equipment. These leases have remaining terms through 2028, one of which includes an option to extend the lease for up to one 5-year term. One lease has fixed rent payments that has escalations based on the CPI. Certain leases contain variable payments.

Services has operating leases for real estate and office equipment. These leases have remaining terms through 2030. Services’ lease for its headquarters, which ends in 2030, includes options to extend for two 5-year terms.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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Operating Lease Costs

The following amounts relate to total operating lease costs, including both amounts recognized in the Consolidated Statements of Operations during the years ended December 31, 2023, 2022 and 2021 and any amounts capitalized as part of the cost of another asset, and the cash flows arising from lease transactions.



	PSE&G			PSEG Power & Other			Total
	Millions
Operating Lease Costs





Year Ended December 31, 2023
Long-term Lease Costs	$	34		$	19		$	53
Short-term Lease Costs	21			6			27
Variable Lease Costs	2			13			15
Total Operating Lease Costs	$	57		$	38		$	95



Year Ended December 31, 2023
Cash Paid for Amounts Included in the Measurement of Operating Lease Liabilities	$	17		$	17		$	34

Weighted Average Remaining Lease Term in Years	10			7			8
Weighted Average Discount Rate	4.0		%	4.2		%	4.1		%



	PSE&G			PSEG Power & Other			Total
	Millions
Operating Lease Costs





Year Ended December 31, 2022
Long-term Lease Costs	$	31		$	25		$	56
Short-term Lease Costs	21			5			26
Variable Lease Costs	2			11			13
Total Operating Lease Costs	$	54		$	41		$	95



Year Ended December 31, 2022
Cash Paid for Amounts Included in the Measurement of Operating Lease Liabilities	$	17		$	25		$	42

Weighted Average Remaining Lease Term in Years	11			7			9
Weighted Average Discount Rate	3.5		%	4.1		%	3.9		%

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	PSE&G			PSEG Power & Other			Total
	Millions
Operating Lease Costs





Year Ended December 31, 2021
Long-term Lease Costs	$	24		$	26		$	50
Short-term Lease Costs	36			6			42
Variable Lease Costs	2			18			20
Total Operating Lease Costs	$	62		$	50		$	112



Year Ended December 31, 2021
Cash Paid for Amounts Included in the Measurement of Operating Lease Liabilities	$	17		$	26		$	43

Weighted Average Remaining Lease Term in Years	12			8			9
Weighted Average Discount Rate	3.4		%	4.1		%	3.8		%

Operating lease liabilities as of December 31, 2023 had the following maturities on an undiscounted basis:



	PSE&G		PSEG Power & Other		Total
	Millions
2024	$	18	$	17	$	35
2025	15		17		32
2026	13		16		29
2027	12		17		29
2028	10		16		26
Thereafter	57		28		85
Total Minimum Lease Payments	$	125	$	111	$	236

The following is a reconciliation of the undiscounted cash flows to the discounted Operating Lease Liabilities recognized on the Consolidated Balance Sheets:



	As of December 31, 2023
	PSE&G		PSEG Power & Other		Total
	Millions
Undiscounted Cash Flows	$	125	$	111	$	236
Reconciling Amount due to Discount Rate	(21)		(15)		(36)
Total Discounted Operating Lease Liabilities	$	104	$	96	$	200

	As of December 31, 2022
	PSE&G		PSEG Power & Other		Total
	Millions
Undiscounted Cash Flows	$	109	$	126	$	235
Reconciling Amount due to Discount Rate	(20)		(18)		(38)
Total Discounted Operating Lease Liabilities	$	89	$	108	$	197

As of December 31, 2023, the current portions of Operating Lease Liabilities included in Other Current Liabilities were $27 million and $15 million for PSEG and PSE&G, respectively. As of December 31, 2022, the current portions of Operating Lease Liabilities included in Other Current Liabilities were $28 million and $12 million for PSEG and PSE&G, respectively.

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Lessor

PSEG Power & Other

Energy Holdings is the lessor in leveraged leases. See Note 8. Long-Term Investments and Note 9. Financing Receivables.

Energy Holdings is the lessor in an operating lease for a domestic energy generation facility with a remaining term through 2036. As of December 31, 2023, Energy Holdings’ property subject to this lease had a total carrying value of $10 million.

In 2022, Energy Holdings recorded pre-tax impairments of $78 million related to one of its domestic energy generating facilities and its real estate assets. In March 2023, Energy Holdings completed the sale of one of its domestic energy generating facilities and recorded an immaterial pre-tax gain. In December 2023, Energy Holdings completed the sale of its real estate assets and recorded an immaterial pre-tax gain.

A wholly owned subsidiary of 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.

Prior to the sale of Solar Source in June 2021, certain of PSEG Power’s sales agreements related to its solar generating plants qualified as operating leases. Lease income was based on solar energy generation; therefore, all rental income recorded under these leases was variable.

The following is the operating lease income for the years ended December 31, 2023, 2022 and 2021:



Operating Lease Income	Millions




Year Ended December 31, 2023
Fixed Lease Income	$	24
Variable Lease Income	—
Total Operating Lease Income	$	24

Year Ended December 31, 2022
Fixed Lease Income	$	31
Variable Lease Income	—
Total Operating Lease Income	$	31

Year Ended December 31, 2021
Fixed Lease Income	$	23
Variable Lease Income	12
Total Operating Lease Income	$	35

Operating leases had the following minimum future fixed lease receipts as of December 31, 2023:



	Millions
2024	$	14
2025	14
2026	14
2027	14
2028	13
Thereafter	110
Total Minimum Future Lease Receipts	$	179

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Note 8. Long-Term Investments

Long-Term Investments as of December 31, 2023 and 2022 included the following:



	As of December 31,
	2023		2022
	Millions
PSE&G
Life Insurance and Supplemental Benefits	$	77	$	81
Solar Loans	40		62
PSEG Power & Other
Lease Investments	161		175
Equity Method Investments (A)	17		306
Total Long-Term Investments	$	295	$	624

(A)During the year ended December 31, 2023, there were no dividends from these investments. During the years ended December 31, 2022 and 2021, dividends from these investments were $8 million and $17 million, respectively. See Note 3. Asset Dispositions and Impairments for information regarding the sales of our ownership interest in the Ocean Wind 1 project and Kalaeloa.

Leases

Energy Holdings, through its indirect subsidiaries, has investments in 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 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, reduced for any income not yet earned on the leases. This amount is included in Long-Term Investments on PSEG’s 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 Consolidated Balance Sheets.

Leveraged leases outstanding as of December 31, 2023 commenced in or prior to 2000.The following table shows Energy Holdings’ gross and net lease investment as of December 31, 2023 and 2022.



	As of December 31,
	2023		2022
	Millions
Lease Receivables (net of Non-Recourse Debt)	$	223	$	249
Estimated Residual Value of Leased Assets	—		—
Total Investment in Rental Receivables	223		249
Unearned and Deferred Income	(62)		(74)
Gross Investments in Leases	161		175
Deferred Tax Liabilities	(36)		(39)
Net Investments in Leases	$	125	$	136

The pre-tax income and income tax effects related to investments in leases were immaterial for the years ended December 31, 2023, 2022 and 2021.

Note 9. Financing Receivables

PSE&G

PSE&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 paid back with 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 December 31, 2023, none of the solar loans were impaired; however, in the event a loan becomes impaired, 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

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and III. A substantial portion of these loan amounts are noncurrent and reported in Long-Term Investments on PSEG’s and PSE&G’s Consolidated Balance Sheets. The following table reflects the outstanding loans by class of customer, none of which would be considered “non-performing.”



	As of December 31,
Outstanding Loans by Class of Customer	2023		2022
	Millions
Commercial/Industrial	$	60	$	85
Residential	3		4
Total	63		89
Current Portion (included in Accounts Receivable)	(23)		(27)
Noncurrent Portion (included in Long-Term Investments)	$	40	$	62

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

Programs

Balance as of December 31, 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 December 31, 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 December 31, 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 had net investments in assets subject to leveraged lease accounting of $125 million as of December 31, 2023 and $136 million as of December 31, 2022 (see Note 8. Long-Term Investments).

The corresponding receivables associated with the lease portfolio are reflected 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 December 31, 2023	As of December 31, 2023
	Millions
AA	$	7
A-	43
BBB+ to BBB	173
Total	$	223

PSEG recorded no credit losses for the leveraged leases existing on December 31, 2023. Upon the occurrence of certain defaults, indirect subsidiaries of Energy Holdings would exercise their rights and seek recovery of their 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.

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Note 10. Trust Investments

NDT Fund

In accordance with NRC regulations, entities owning an interest in nuclear generating facilities are required to determine the costs and funding methods necessary to decommission such facilities upon termination of operation. As a general practice, each nuclear owner places funds in independent external trust accounts it maintains to provide for decommissioning. PSEG Power is required to file periodic reports with the NRC demonstrating that its NDT Fund meets the formula-based minimum NRC funding requirements. 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. PSEG Power’s share of decommissioning costs related to its five nuclear units was estimated to be between $3.0 billion and $3.4 billion, including contingencies. The liability for decommissioning recorded on a discounted basis as of December 31, 2023 was approximately $1.1 billion and is included in the ARO. The funds are managed by third-party investment managers who operate under investment guidelines developed by PSEG Power.

The following tables show the fair values and gross unrealized gains and losses for the securities held in the NDT Fund.



	As of December 31, 2023
	Cost		Gross Unrealized Gains		Gross Unrealized Losses		Fair Value
	Millions
Equity Securities
Domestic	$	482	$	300	$	(2)	$	780
International	423		118		(11)		530
Total Equity Securities	905		418		(13)		1,310
Available-for-Sale Debt Securities
Government	759		4		(72)		691
Corporate	555		6		(39)		522
Total Available-for-Sale Debt Securities	1,314		10		(111)		1,213
Total NDT Fund Investments (A)	$	2,219	$	428	$	(124)	$	2,523

(A) The NDT Fund Investments table excludes cash and foreign currency of $1 million as of December 31, 2023,

which is part of the NDT Fund.



	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.

Net unrealized gains (losses) on debt securities of $(59) million (after-tax) were included in Accumulated Other Comprehensive Loss on PSEG’s Consolidated Balance Sheet as of December 31, 2023. The portion of net unrealized gains (losses) recognized

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during 2023 related to equity securities still held at the end of December 31, 2023 was $166 million.

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 Consolidated Balance Sheets as shown in the following table.



	As of December 31,
	2023		2022
	Millions
Accounts Receivable	$	19	$	14
Accounts Payable	$	6	$	6

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 December 31, 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	$	44	$	(1)	$	4	$	—	$	90	$	(10)	$	9	$	(2)
International	35		(4)		28		(8)		88		(12)		38		(16)
Total Equity Securities	79		(5)		32		(8)		178		(22)		47		(18)
Available-for-Sale Debt Securities
Government (B)	90		(1)		432		(71)		301		(27)		292		(67)
Corporate (C)	19		—		329		(39)		221		(21)		249		(48)
Total Available-for-Sale Debt Securities	109		(1)		761		(110)		522		(48)		541		(115)
NDT Trust Investments	$	188	$	(6)	$	793	$	(118)	$	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.

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



	Years Ended December 31,
	2023		2022		2021
	Millions
Proceeds from Sales (A)	$	1,685	$	1,521	$	1,930
Net Realized Gains (Losses):
Gross Realized Gains	$	142	$	86	$	236
Gross Realized Losses	(100)		(136)		(70)
Net Realized Gains (Losses) on NDT Fund (B)	42		(50)		166
Net Unrealized Gains (Losses) on Equity Securities	146		(205)		19

Net Gains (Losses) on NDT Fund Investments	$	188	$	(255)	$	185

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

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

The NDT Fund debt securities held as of December 31, 2023 had the following maturities:



Time Frame	Fair Value
	Millions
Less than one year	$	17
1 - 5 years	314
6 - 10 years	214
11 - 15 years	62
16 - 20 years	101
Over 20 years	505
Total NDT Available-for-Sale Debt Securities	$	1,213

PSEG Power periodically assesses individual debt securities whose fair value is less than amortized cost to determine whether the investments are impaired. For 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). Any subsequent recoveries of the 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 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.”

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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 December 31, 2023
	Cost		Gross Unrealized Gains		Gross Unrealized Losses		Fair Value
	Millions
Domestic Equity Securities	$	10	$	8	$	—	$	18
Available-for-Sale Debt Securities
Government	110		—		(19)		91
Corporate	80		—		(10)		70
Total Available-for-Sale Debt Securities	190		—		(29)		161
Total Rabbi Trust Investments	$	200	$	8	$	(29)	$	179



	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 $(21) million (after-tax) were included in Accumulated Other Comprehensive Loss on PSEG’s Consolidated Balance Sheet as of December 31, 2023. The portion of net unrealized gains (losses) recognized during 2023 related to equity securities still held at the end of December 31, 2023 was $2 million.

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 Consolidated Balance Sheets as shown in the following table.



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

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



	As of December 31, 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)	$	3	$	—	$	83	$	(19)	$	32	$	(5)	$	57	$	(16)
Corporate (B)	3		—		60		(10)		35		(5)		39		(10)
Total Available-for-Sale Debt Securities	6		—		143		(29)		67		(10)		96		(26)
Rabbi Trust Investments	$	6	$	—	$	143	$	(29)	$	67	$	(10)	$	96	$	(26)

(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 gains (losses) on securities in the Rabbi Trust Fund were:



	Years Ended December 31,
	2023		2022		2021
	Millions
Proceeds from Rabbi Trust Sales	$	29	$	65	$	170
Net Realized Gains (Losses):
Gross Realized Gains	$	5	$	5	$	16
Gross Realized Losses	(6)		(9)		(8)
Net Realized Gains (Losses) on Rabbi Trust (A)	(1)		(4)		8
Net Unrealized Gains (Losses) on Equity Securities	2		(6)		1
Net Gains (Losses) on Rabbi Trust Investments	$	1	$	(10)	$	9

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

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The Rabbi Trust debt securities held as of December 31, 2023 had the following maturities:



Time Frame	Fair Value
	Millions
Less than one year	$	8
1 - 5 years	27
6 - 10 years	16
11 - 15 years	10
16 - 20 years	20
Over 20 years	80
Total Rabbi Trust Available-for-Sale Debt Securities	$	161

PSEG periodically assesses individual debt securities whose fair value is less than amortized cost to determine whether the investments are considered to be impaired. For 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). Any subsequent recoveries of the 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 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 and PSE&G are detailed as follows:



	As of December 31,		As of December 31,
	2023		2022
	Millions
PSE&G	$	32	$	32
PSEG Power & Other	147		151
Total Rabbi Trust Investments	$	179	$	183

Note 11. Asset Retirement Obligations (AROs)

PSEG and PSE&G recognize liabilities for the expected cost of retiring long-lived assets for which a legal obligation exists to remove or dispose of an asset or some component of an asset at retirement. These AROs are recorded at fair value in the period in which they are incurred and are capitalized as part of the carrying amount of the related long-lived assets. PSEG’s subsidiaries, except for PSE&G, accrete the ARO liability to reflect the passage of time with the corresponding expense recorded in O&M. PSE&G, as a rate-regulated entity, recognizes Regulatory Assets or Liabilities as a result of timing differences between the recording of costs and costs recovered through the rate-making process.

PSE&G has conditional AROs primarily for legal obligations related to the removal of treated wood poles and the requirement to seal natural gas pipelines at all sources of gas when the pipelines are no longer in service. PSE&G does not record an ARO for its protected steel and poly-based natural gas lines, as management believes that these categories of gas lines have an indeterminable life.

PSEG’s other ARO liability primarily relates to decommissioning of its nuclear power plants in accordance with NRC requirements. PSEG has an independent external trust that is intended to fund decommissioning of its nuclear facilities upon termination of operation. For additional information, see Note 10. Trust Investments. PSEG also identified conditional AROs related to PSEG’s retained fossil generation sites primarily related to liabilities for removal of asbestos. To estimate the fair value of its other AROs, PSEG uses a probability weighted, discounted cash flow model which, on a unit by unit basis, considers multiple outcome scenarios that include significant estimates and assumptions, and are based on third-party decommissioning cost estimates, cost escalation rates, inflation rates and discount rates.

Updated nuclear cost studies are obtained triennially unless new information necessitates more frequent updates. The most recent cost study was done in 2021. When assumptions are revised to calculate fair values of existing AROs, generally, the ARO balance and corresponding long-lived asset are adjusted which impact the amount of accretion and depreciation expense

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recognized in future periods. For PSE&G, Regulatory Assets and Regulatory Liabilities result when accretion and amortization are adjusted to match rates established by regulators resulting in the regulatory deferral of any gain or loss.

The changes to the ARO liabilities for PSEG and PSE&G during 2022 and 2023 are presented in the following table:



	PSEG		PSE&G		PSEG Power & Other
	Millions
ARO Liability as of January 1, 2022	$	1,573	$	363	$	1,210
Liabilities Settled	(15)		(15)		—
Accretion Expense	50		—		50
Accretion Expense Deferred and Recovered in Rate Base (A)	17		17		—
Revision to Present Values of Estimated Cash Flows	(126)		19		(145)
ARO Liability as of December 31, 2022	$	1,499	$	384	$	1,115
Liabilities Settled	$	(13)	$	(13)	$	—

Accretion Expense	51		—		51
Accretion Expense Deferred and Recovered in Rate Base (A)	16		16		—
Revision to Present Values of Estimated Cash Flows	(85)		14		(99)
ARO Liability as of December 31, 2023	$	1,468	$	401	$	1,067

(A)Not reflected as expense in Consolidated Statements of Operations.

In February 2022, the NRC issued an order related to its review of the subsequent license renewal (SLR) application for the Peach Bottom nuclear units. While the NRC had previously granted the SLR to the Peach Bottom units, the NRC was responding to pending motions that had not previously been adjudicated. In its decision, the NRC concluded that the previous environmental review required by the National Environmental Policy Act (NEPA) was incomplete because it did not adequately address environmental impacts resulting from extending the units’ licenses by 20 years. As a result, at the direction of the NRC, the NRC staff changed the expiration dates for the licenses back to 2033 and 2034, until the completion of the NEPA analysis. The NRC directed, however, that the subsequently renewed licenses themselves remain in effect. The NRC also stated that it fully expects that the staff will complete its update of the NEPA analysis before 2033. As such, at this time, PSEG has not adjusted the useful lives or the assumed shutdown probabilities assigned to the ARO of the units as PSEG believes that the licenses will be updated to reflect the approved 2053 and 2054 expiration dates within the current license period. PSEG will continue to monitor this matter for further developments and any change to the estimated useful lives and ARO probabilities could have an adverse financial statement impact, which may be material.

In August 2022, the Inflation Reduction Act (IRA) was signed into law expanding incentives promoting carbon-free generation. The enacted legislation established a PTC for electricity generation using nuclear energy set to begin January 1, 2024 and continue through 2032. As a result, PSEG reassessed the Asset Retirement Cost (ARC) and ARO assumptions related to its nuclear units. This resulted in a decrease to the ARC asset and ARO liability of $145 million primarily due to an adjustment in the assumed estimated timing of cash flows associated with decommissioning the units.

In December 2023, PSEG Power reassessed its ARC and ARO assumptions related to its Hope Creek and Salem nuclear plants, based upon the expectation of PTCs beginning in 2024. As a result, PSEG Power decreased its ARC asset and ARO liability by $99 million, reflecting a decrease in the probability of early retirement and an increase in the probability the units would obtain additional license renewals.

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Note 12. Pension, Other Postretirement Benefits (OPEB) and Savings Plans

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. PSEG’s qualified pension plans consist of two qualified defined benefit pension plans, Pension Plan of Public Service Enterprise Group Incorporated (Pension Plan I) and Pension Plan of Public Service Enterprise Group Incorporated II (Pension Plan II and, together, the Plans). Each of the qualified pension plans include a Final Average Pay and two Cash Balance components. In addition, represented and non-represented employees are eligible for participation in PSEG’s two defined contribution plans.

PSEG and PSE&G are required to record the under or over funded positions of their defined benefit pension and OPEB plans on their respective balance sheets. Such funding positions are required to be measured as of the date of their respective year-end Consolidated Balance Sheets. For underfunded plans, the liability is equal to the difference between the plan’s benefit obligation and the fair value of plan assets. For defined benefit pension plans, the benefit obligation is the projected benefit obligation. For OPEB plans, the benefit obligation is the accumulated postretirement benefit obligation. In addition, GAAP requires that the total unrecognized costs for defined benefit pension and OPEB plans be recorded as an after-tax charge to Accumulated Other Comprehensive Income (Loss), a separate component of Stockholders’ Equity. However, for PSE&G, because the amortization of the unrecognized costs is being collected from customers, the accumulated unrecognized costs are recorded as a Regulatory Asset. The unrecognized costs represent actuarial gains or losses and prior service costs which have not been expensed. The charge to Accumulated Other Comprehensive Income (Loss) and the Regulatory Asset for PSE&G are amortized and recorded as net periodic pension cost in the Consolidated Statements of Operations.

In July 2023, PSEG and Fiduciary Counselors Inc,. as independent fiduciary of 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 has transferred 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). In August 2023, assets were transferred to the Insurer and the transaction was closed. Under the contract, the Insurer made an irrevocable commitment, and is solely responsible, to pay benefits of each Participant that are due on and after December 31, 2023. The transaction resulted in no changes to the amount of benefits payable to Participants.

Amounts for Servco are not included in any of the following pension and OPEB benefit information for PSEG and its affiliates but rather are separately disclosed later in this note.

The following table provides a roll-forward of the changes in the benefit obligation and the fair value of plan assets during each of the two years in the periods ended December 31, 2023 and 2022. It also provides the funded status of the plans and the amounts recognized and amounts not recognized on the Consolidated Balance Sheets at the end of both years.

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	Pension Benefits				Other Benefits
	2023		2022		2023		2022
	Millions
Change in Benefit Obligation
Benefit Obligation at Beginning of Year (A)	$	5,628	$	7,240	$	851	$	1,197
Service Cost	90		142		3		6
Interest Cost	259		167		41		26
Actuarial (Gain) Loss (B)	103		(1,517)		(30)		(314)
Gross Benefits Paid	(352)		(382)		(68)		(61)
Settlements	(970)		—		—		—
Other	—		(22)		5		(3)
Benefit Obligation at End of Year (A)	$	4,758	$	5,628	$	802	$	851
Change in Plan Assets
Fair Value of Assets at Beginning of Year	$	4,911	$	6,906	$	429	$	606
Actual Return on Plan Assets	539		(1,606)		51		(139)
Employer Contributions	12		11		28		23
Gross Benefits Paid	(352)		(382)		(68)		(61)
Settlements	(970)		—		—		—
Other	—		(18)		—		—
Fair Value of Assets at End of Year	$	4,140	$	4,911	$	440	$	429
Funded Status
Funded Status (Plan Assets less Benefit Obligation)	$	(618)	$	(717)	$	(362)	$	(422)
Additional Amounts Recognized in the Consolidated Balance Sheets
Current Accrued Benefit Cost	$	(12)	$	(12)	$	(13)	$	(12)
Noncurrent Accrued Benefit Cost	(606)		(705)		(349)		(410)
Amounts Recognized	$	(618)	$	(717)	$	(362)	$	(422)
Additional Amounts Recognized in Accumulated Other Comprehensive Income (Loss), Regulated Assets and Deferred Assets (C)
Prior Service Cost (Credit)	$	—	$	—	$	6	$	(52)
Net Actuarial Loss (Gain)	1,656		2,151		(6)		41
Total	$	1,656	$	2,151	$	—	$	(11)

(A)Represents projected benefit obligation for pension benefits and the accumulated postretirement benefit obligation for other benefits. The vested benefit obligation is the actuarial present value of the vested benefits to which the employee is currently entitled but based on the employee’s expected date of separation or retirement.

(B)For pension benefits, the net actuarial loss in 2023 was due primarily to a decrease in the discount rate. The net actuarial gain in 2022 was due primarily to an increase in the discount rate. For OPEB, the net actuarial gain in 2023 was due primarily to assumption updates. The net actuarial gain in 2022 was due primarily to an increase in the discount rate and other assumption updates.

(C)Includes $143 million ($102 million, after-tax) and $594 million ($426 million, after-tax) in Accumulated Other Comprehensive Loss related to Pension and OPEB as of December 31, 2023 and 2022, respectively. Also includes Regulatory Assets of $1,427 million and Deferred Assets of $141 million as of December 31, 2023 and Regulatory Assets of $1,405 million and Deferred Assets of $141 million as of December 31, 2022. This amount does not include $55 million as a result of modifying the method for calculating pension expense for ratemaking purposes, approved by the BPU effective January 1, 2023.

The pension benefits table above provides information relating to the funded status of the qualified and nonqualified pension and OPEB plans on an aggregate basis. As of December 31, 2023, PSEG had funded approximately 87% of its projected pension benefit obligation. This percentage does not include $179 million of assets in the Rabbi Trust as of December 31, 2023, which provide funding for the nonqualified pension plans and certain deferred compensation. The nonqualified pension plans included in the projected benefit obligation in the above table were $140 million.

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Accumulated Benefit Obligation

The accumulated benefit obligation for all PSEG’s defined benefit pension plans was $4.7 billion as of December 31, 2023 and $5.5 billion as of December 31, 2022.

The following table provides the components of net periodic benefit relating to all qualified and nonqualified pension and OPEB plans on an aggregate basis for PSEG, excluding Servco for the years ended December 31, 2023, 2022 and 2021. 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 Years Ended December 31,						Other Benefits Years Ended December 31,
	2023		2022		2021		2023		2022		2021
	Millions
Components of Net Periodic Benefit (Credits) Costs
Service Cost (included in O&M Expense)	$	90	$	142	$	151	$	3	$	6	$	9
Non-Service Components of Pension and OPEB (Credits) Costs
Interest Cost	259		167		140		41		26		22
Expected Return on Plan Assets	(361)		(484)		(476)		(33)		(42)		(42)
Amortization of Net
Prior Service Credit	—		—		—		(52)		(129)		(129)
Actuarial Loss	83		60		103		(2)		15		44
Settlement Charge Resulting from Pension Lift-Out	338		—		—		—		—		—
Non-Service Components of Pension and OPEB (Credits) Costs	319		(257)		(233)		(46)		(130)		(105)
Total Net Benefit (Credits) Costs	$	409	$	(115)	$	(82)	$	(43)	$	(124)	$	(96)

Pension and OPEB (credits) costs for PSEG and PSE&G are detailed as follows:



	Pension Benefits Years Ended December 31,						Other Benefits Years Ended December 31,
	2023		2022		2021		2023		2022		2021
	Millions
PSE&G	$	50	$	(70)	$	(64)	$	(42)	$	(109)	$	(92)
PSEG Power & Other	359		(45)		(18)		(1)		(15)		(4)
Total Net Benefit (Credits) Costs	$	409	$	(115)	$	(82)	$	(43)	$	(124)	$	(96)

PSEG completed the above mentioned “lift-out” transaction in August 2023. As a result of the transaction, PSEG recognized a settlement charge of $332 million ($239 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. Additionally, a settlement charge of $6 million ($4 million, net of tax) related to lump sum payments to participants was recognized in the fourth quarter of 2023.

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The following table provides the pre-tax changes recognized in Accumulated Other Comprehensive Income (Loss), Regulatory Assets and Deferred Assets:



	Pension				Other Benefits
	2023		2022		2023		2022
	Millions
Net Actuarial (Gain) Loss in Current Period due to Plan Experience and Assumption Changes	$	(35)	$	568	$	(49)	$	(138)
Net Actuarial (Gain) Loss due to Settlements/Curtailments	(39)		—		—		—
Amortization of Net Actuarial Gain (Loss)	(83)		(60)		2		(14)
Recognition of Net Actuarial (Gain) Loss due to Settlements/Curtailments	(338)		—		—		—
Prior Service Cost (Credit) in Current Period	—		—		6		—
Amortization of Prior Service Credit	—		—		52		129
Total	$	(495)	$	508	$	11	$	(23)

The following assumptions were used to determine the benefit obligations and net periodic benefit costs:



	Pension Benefits						Other Benefits
	2023		2022		2021		2023		2022		2021

Weighted-Average Assumptions Used to Determine Benefit Obligations as of December 31
Discount Rate	5.02	%	5.20	%	2.94	%	4.96	%	5.16	%	2.82	%
Rate of Compensation Increase	4.60	%	4.40	%	4.40	%	4.60	%	4.40	%	4.40	%
Cash Balance Interest Crediting Rate	6.00	%	6.00	%	6.00	%	N/A		N/A		N/A
Weighted-Average Assumptions Used to Determine Net Periodic Benefit Cost for Years Ended December 31
Discount Rate	5.20	%	2.94	%	2.61	%	5.16	%	2.82	%	2.46	%
Service Cost Interest Rate	5.31	%	3.19	%	2.94	%	5.23	%	3.06	%	2.76	%
Interest Cost Interest Rate	5.09	%	2.37	%	1.91	%	5.07	%	2.21	%	1.70	%
Expected Return on Plan Assets	8.10	%	7.20	%	7.70	%	8.10	%	7.20	%	7.69	%
Rate of Compensation Increase	4.40	%	4.40	%	4.40	%	4.40	%	4.40	%	4.40	%
Cash Balance Interest Crediting Rate	6.00	%	6.00	%	6.00	%	N/A		N/A		N/A
Assumed Health Care Cost Trend Rates as of December 31

Health Care Costs
Immediate Rate							8.89	%	6.98	%	6.14	%
Ultimate Rate							4.75	%	4.75	%	4.75	%
Year Ultimate Rate Reached							2033		2032		2029

Plan Assets

The investments of pension and OPEB plans are held in a trust account by the Trustee and consist of an undivided interest in an investment account of the Master Trust. The investments in the pension and OPEB plans are measured at fair value within a hierarchy that prioritizes the inputs to fair value measurements into three levels. See Note 17. Fair Value Measurements for more information on fair value guidance. Use of the Master Trust permits the commingling of pension plan assets and OPEB plan assets for investment and administrative purposes. Although assets of the plans are commingled in the Master Trust, the Trustee maintains supporting records for the purpose of allocating the net gain or loss of the investment account to the respective participating plans. The net investment income of the investment assets is allocated by the Trustee to each participating plan based on the relationship of the interest of each plan to the total of the interests of the participating plans. As of December 31, 2023, the pension plan interest and OPEB plan interest in such assets of the Master Trust were approximately 90% and 10%, respectively.

The following tables present information about the investments measured at fair value on a recurring basis as of December 31, 2023 and 2022, including the fair value measurements and the levels of inputs used in determining those fair values.

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	Recurring Fair Value Measurements as of December 31, 2023
			Quoted Market Prices for Identical Assets		Significant Other Observable Inputs
Description	Total		(Level 1)		(Level 2)
	Millions
Cash Equivalents (A)	$	39	$	39	$	—
Equity Securities
Common Stock (B)	748		748		—
Commingled (C)	1,376		—		1,376
Debt Securities (D)
U.S. Treasury	1,299		—		1,299
Commingled	4		4		—
Subtotal Fair Value	$	3,466	$	791	$	2,675
Measured at net asset value practical expedient
Commingled—Equities (E)	745
Real Estate Investment (F)	365
Other	2
Total Fair Value (G)	$	4,578



	Recurring Fair Value Measurements as of December 31, 2022
			Quoted Market Prices for Identical Assets		Significant Other Observable Inputs
Description	Total		(Level 1)		(Level 2)
	Millions
Cash Equivalents (A)	$	36	$	36	$	—
Equity Securities
Common Stock (B)	1,231		1,231		—
Commingled (C)	1,346		—		1,346
Debt Securities (D)
U.S. Treasury	1,351		—		1,351
Commingled	4		4		—
Subtotal Fair Value	$	3,968	$	1,271	$	2,697
Measured at net asset value practical expedient
Commingled—Equities (E)	965
Real Estate Investment (F)	395
Other	3
Total Fair Value (G)	$	5,331

(A)The Collective Investment Fund publishes a daily net asset value (NAV) which participants may use for daily redemptions without restrictions (Level 1).

(B)Common stocks are measured using observable data in active markets and considered Level 1.

(C)Commingled Funds that publish daily NAV but with certain near-term redemption restrictions which prevent redemption at the published daily NAV are classified as Level 2.

(D)Debt securities include mainly U.S. Treasury obligations. These investments are valued using an evaluated pricing approach 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 or the most recent quotes for similar securities which are a Level 2 measure.

(E)Certain commingled equity funds are not included in the fair value hierarchy as they are measured at fair value using the NAV per share (or its equivalent) practical expedient. These funds do not meet the definition of readily

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determinable fair value due to the frequency of publishing NAV (monthly). The objectives of these funds are mainly tracking the S&P Index or achieving long-term growth through investment in foreign equity securities and the Morgan Stanley Capital International Index.

(F)The unlisted real estate fund invests in office, apartment, industrial and retail space. The fund is valued using the NAV per unit of funds. The investment value of the real estate properties is determined on a quarterly basis by independent market appraisers engaged by the board of directors of the fund. The ability to redeem funds is subject to the availability of cash arising from net investment income, allocations and the sale of investments in the normal course of business. The fund’s NAV is published quarterly. In addition, redemptions require one quarter advance notice prior to redemption and are fulfilled quarterly. The fund, therefore, does not meet the definition of readily determinable fair value. The purpose of the fund is to acquire, own, hold for investment and ultimately dispose of investments in real estate and real estate-related assets with the intention of achieving current income, capital appreciation or both.

(G)Excludes net receivables of $2 million and $7 million as of December 31, 2023 and 2022, respectively, which consist of interest, dividends and receivables and payables related to pending securities sales and purchases. In addition, the table excludes cash and foreign currency of $2 million as of December 31, 2022.

The following table provides the percentage of fair value of total plan assets for each major category of plan assets held for the qualified pension and OPEB plans as of the measurement date, December 31:



	As of December 31,
Investments	2023		2022
Equity Securities	63	%	67	%
Debt Securities	28		25
Other Investments	9		8
Total Percentage	100	%	100	%

PSEG utilizes forecasted returns, risk, and correlation of all asset classes in order to develop an efficient portfolio. PSEG’s long-term target asset allocation of 54% equities, 18% real assets and 28% fixed income is consistent with the funds’ financial objectives. Certain investments in real assets (13% as of December 31, 2023) are made through investing in equity securities and tracked as equities when reporting fair value; however, they are viewed by their asset class, real assets, in our target asset allocation. Derivative financial instruments are used by the plans’ investment managers primarily to adjust the fixed income duration of the portfolio and hedge the currency risk component of foreign investments. The expected long-term rate of return on plan assets was 8.1% for 2023 and will remain at 8.1% for 2024. This expected return includes a premium for active management.

Plan Contributions

PSEG plans to contribute $5 million to its OPEB plan and does not plan to contribute to its pension plans in 2024. Internal Revenue Service (IRS) minimum funding requirements for pension plans are determined based on the fund’s assets and liabilities at the end of a calendar year for the subsequent calendar year.

Estimated Future Benefit Payments

The following pension benefit and postretirement benefit payments are expected to be paid to plan participants.



Year	Pension Benefits		Other Benefits
	Millions
2024	$	364	$	74
2025	325		73
2026	331		71
2027	338		69
2028	343		67
2029-2033	1,758		288
Total	$	3,459	$	642

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401(k) Plans

PSEG sponsors two 401(k) plans, which are defined contribution retirement plans subject to the Employee Retirement Income Security Act (ERISA). Eligible represented employees of PSEG’s subsidiaries participate in the PSEG Employee Savings Plan (Savings Plan), while eligible non-represented employees of PSEG’s subsidiaries participate in the PSEG Thrift and Tax-Deferred Savings Plan (Thrift Plan). Eligible employees may contribute up to 50% of their annual eligible compensation to these plans, not to exceed the IRS maximums, including any catch-up contributions for those employees age 50 and above. PSEG matches 50% of such employee contributions up to 7% of pay for Savings Plan participants and up to 8% of pay for Thrift Plan participants. The amounts paid for employer matching contributions to the plans for PSEG and PSE&G are detailed as follows:



	Thrift Plan and Savings Plan
	Years Ended December 31,
	2023		2022		2021
	Millions
PSE&G	$	29	$	28	$	28
PSEG Power & Other	14		14		16
Total Employer Matching Contributions	$	43	$	42	$	44

Servco Pension and OPEB

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

The following table provides a roll-forward of the changes in Servco’s benefit obligation and the fair value of its plan assets during the years ended December 31, 2023 and 2022. It also provides the funded status of the plans and the amounts recognized and amounts not recognized on the Consolidated Balance Sheets at the end of both years.



	Pension Benefits				Other Benefits
	2023		2022		2023		2022
	Millions
Change in Benefit Obligation
Benefit Obligation at Beginning of Year (A)	$	452	$	596	$	455	$	640
Service Cost	24		38		12		21
Interest Cost	23		17		24		19
Actuarial (Gain) Loss (B)	31		(189)		35		(215)
Plan Amendment	16		—		—		—
Gross Benefits Paid	(11)		(10)		(12)		(10)
Benefit Obligation at End of Year (A)	$	535	$	452	$	514	$	455
Change in Plan Assets
Fair Value of Assets at Beginning of Year	$	370	$	422	$	—	$	—
Actual Return on Plan Assets	56		(72)		—		—
Employer Contributions	18		30		12		10
Gross Benefits Paid	(11)		(10)		(12)		(10)
Fair Value of Assets at End of Year	$	433	$	370	$	—	$	—
Funded Status
Funded Status (Plan Assets less Benefit Obligation)	$	(102)	$	(82)	$	(514)	$	(455)
Additional Amounts Recognized in the Consolidated Balance Sheets
Accrued Pension Costs of Servco	$	(102)	$	(82)	N/A		N/A
OPEB Costs of Servco	N/A		N/A		(514)		(455)
Amounts Recognized (C)	$	(102)	$	(82)	$	(514)	$	(455)

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(B)For pension and OPEB benefits, the net actuarial losses in 2023 were due primarily to a decrease in the discount rate and other assumption updates. For pension benefits and OPEB, the net actuarial gains in 2022 were due primarily to an increase in the discount rate.

(C)Amounts equal to the accrued pension and OPEB costs of Servco are offset in Long-Term Receivable of VIE on PSEG’s Consolidated Balance Sheets.

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. The pension-related revenues and costs for 2023, 2022 and 2021 were $18 million, $30 million and $37 million, respectively. Servco has contributed its entire planned contribution amount to its pension plan trusts during 2023. The OPEB-related revenues earned and costs incurred were $12 million, $10 million and $11 million in 2023, 2022 and 2021, respectively.

The following assumptions were used to determine the benefit obligations of Servco:



	Pension Benefits						Other Benefits
	2023		2022		2021		2023		2022		2021
Weighted-Average Assumptions Used to Determine Benefit Obligations as of December 31
Discount Rate	5.13	%	5.30	%	3.21	%	5.16	%	5.34	%	3.28	%
Rate of Compensation Increase	5.54	%	3.95	%	3.95	%	5.54	%	3.95	%	3.95	%
Cash Balance Interest Crediting Rate	4.13	%	4.30	%	3.75	%	N/A		N/A		N/A
Assumed Health Care Cost Trend Rates as of December 31
Health Care Costs
Immediate Rate							6.84	%	6.71	%	6.48	%
Ultimate Rate							4.75	%	4.75	%	4.75	%
Year Ultimate Rate Reached							2033		2032		2029

Plan Assets

All the investments of Servco’s pension plans are held in a trust account by the Trustee and consist of an undivided interest in an investment account of the Servco Master Trust. The investments in the pension are measured at fair value within a hierarchy that prioritizes the inputs to fair value measurements into three levels. See Note 17. Fair Value Measurements for more information on fair value guidance.

The following tables present information about Servco’s investments measured at fair value on a recurring basis as of December 31, 2023 and 2022, including the fair value measurements and the levels of inputs used in determining those fair values.



	Recurring Fair Value Measurements as of December 31, 2023
			Quoted Market Prices for Identical Assets		Significant Other Observable Inputs
Description	Total		(Level 1)		(Level 2)
	Millions
Cash Equivalents	$	2	$	2	$	—
Equity Securities
Common Stock (A)	32		32		—
Commingled (B)	294		—		294
Commingled Bonds (B)	105		—		105
Total Fair Value	$	433	$	34	$	399

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	Recurring Fair Value Measurements as of December 31, 2022
			Quoted Market Prices for Identical Assets		Significant Other Observable Inputs
Description	Total		(Level 1)		(Level 2)
	Millions
Cash Equivalents	$	1	$	1	$	—
Equity Securities
Common Stock (A)	25		25		—
Commingled (B)	251		—		251
Commingled Bonds (B)	93		—		93
Total Fair Value	$	370	$	26	$	344

(A)Common stocks are measured using observable data in active markets and considered Level 1.

(B)Investments in commingled equity and bond funds have a readily determinable fair value as they publish a daily NAV available to investors which is the basis for current transactions and contain certain redemption restrictions requiring advance notice of one to two days for withdrawals (Level 2).

The following table provides the percentage of fair value of total plan assets for each major category of plan assets held for the qualified pension and OPEB plans of Servco as of the measurement date, December 31:



	As of December 31,
Investments	2023		2022
Equity Securities	76	%	75	%
Debt Securities	24		25
Total Percentage	100	%	100	%

Servco utilizes forecasted returns, risk, and correlation of all asset classes in order to develop an efficient portfolio. Servco’s long-term target asset allocation of 60% equities, 15% real assets and 25% fixed income is consistent with the funds’ financial objectives. Certain investments in real assets (15% at December 31, 2023) are made through investing in equity securities and tracked as equities when reporting fair value; however, they are viewed by their asset class, real assets, in our target asset allocation. The expected long-term rate of return on plan assets was 8.0% for 2023 and will be 8.0% for 2024. This expected return includes a premium for active management.

Plan Contributions

Servco plans to contribute $25 million into its pension plan during 2024.

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Estimated Future Benefit Payments

The following pension benefit and postretirement benefit payments are expected to be paid to Servco’s plan participants:



Year	Pension Benefits		Other Benefits
	Millions
2024	$	15	$	12
2025	17		14
2026	20		16
2027	23		18
2028	25		20
2029-2033	167		125
Total	$	267	$	205

Servco 401(k) Plans

Servco sponsors two 401(k) plans, which are defined contribution retirement plans subject to ERISA. Eligible non-represented employees of Servco participate in the Long Island Electric Utility Servco LLC Incentive Thrift Plan I (Thrift Plan I), and eligible represented employees of Servco participate in the Long Island Electric Utility Servco LLC Incentive Thrift Plan II (Thrift Plan II). Participants in the plans may contribute up to 50% of their eligible compensation to these plans, not to exceed the IRS maximums, including any catch-up contributions for those employees age 50 and above. Servco does not provide an employer match or core contribution for employees in Thrift Plan II. For employees in Thrift Plan I, Servco matches 50% of such employee contributions up to 8% of eligible compensation and provides core contributions (based on years of service and age) to employees who do not participate in Servco’s Retirement Income Plan. The amount expensed by Servco for employer matching contributions was $10 million for the year ended December 31, 2023, and $9 million for each of the years ended December 31, 2022 and 2021. Pursuant to the OSA, Servco recognizes Operating Revenues for the reimbursement of these costs.

Note 13. 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 on 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

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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 obligations.

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



	As of December 31,
	2023		2022
	Millions
Face Value of Outstanding Guarantees	$	1,381	$	1,601
Exposure under Current Guarantees	$	118	$	198

Letters of Credit Margin Posted	$	10	$	87
Letters of Credit Margin Received	$	91	$	38

Cash Deposited and Received
Counterparty Cash Collateral Deposited	$	—	$	—
Counterparty Cash Collateral Received	$	(2)	$	(1)
Net Broker Balance Deposited (Received)	$	115	$	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 contracts. See Note 16. 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 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.

Environmental Matters

Passaic River

Lower Passaic River Study Area

The U.S. Environmental Protection Agency (EPA) has determined that a 17-mile stretch of the Passaic River (Lower Passaic River Study Area (LPRSA)) in New Jersey is a “Superfund” site under the Federal Comprehensive Environmental Response, Compensation and Liability Act of 1980 (CERCLA). PSE&G and certain of its predecessors conducted operations at properties in this area, including at one 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. PSEG cannot predict the outcome of the litigation.

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The EPA has announced a proposed settlement with 82 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 are not included in the proposed settlement, but the EPA sent PSE&G, Occidental, and several other Potentially Responsible Parties (PRPs) 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 PSEG Power. PSEG understands that the EPA is evaluating its offer.

As of December 31, 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 continued ability to recover such costs in its rates. PSEG Power has an Environmental Costs Liability of $13 million.

The outcome of this matter is uncertain, and until (i) a final remedy for the entire LPRSA is selected and an agreement is reached by the PRPs to fund it, (ii) PSE&G’s and PSEG Power’s respective shares of the costs are determined, and (iii) PSE&G’s 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.

Newark Bay Study Area

The EPA has established the Newark Bay Study Area, which is an extension of the LPRSA and includes Newark Bay and portions of surrounding waterways. The EPA has notified PSEG and 21 other PRPs of 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.

Hackensack River

In 2022, the EPA announced it had designated approximately 23 river miles of the Lower Hackensack River as 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. In 2024, the EPA identified PSE&G and four other parties as PRPs for the site and requested that they voluntarily perform a technical study of a portion of the river designated as “Operable Unit 2.” The EPA estimates that the technical study will cost $55 million to complete. The EPA may take enforcement action against parties that do not cooperate. PSE&G and PSEG Power do not believe participation in the technical study will have a material impact on their results of operations and financial condition based upon EPA’s estimate of the study costs, however, future costs related to this matter could be material.

MGP Remediation Program

PSE&G is working with the 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 $199 million and $219 million on an undiscounted basis, including its $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 $199 million as of December 31, 2023. Of this amount, $52 million was recorded in Other Current Liabilities and $147 million was reflected as Environmental Costs in Noncurrent Liabilities. PSE&G has recorded a $199 million Regulatory 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. PSE&G completed sampling in the Passaic River in 2020 to delineate coal tar from certain MGP sites that abut the Passaic River Superfund site. PSEG cannot determine at this time the magnitude of any impact on the Passaic River Superfund remedy.

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Legacy Environmental Obligations at Former Fossil Generating Sites

PSEG Power has retained ownership of certain liabilities excluded from the 2022 sale of its fossil generation portfolio. These liabilities primarily relate to obligations under the New Jersey 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 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 investigate these sites. It will require multiple years and comprehensive environmental sampling to understand the extent of and to carry out the required remediation. At this stage in the remediation process, the full remediation costs are not estimable, but given the number and operating history of the facilities in the portfolio, the full remediation costs will likely be material in the aggregate. The costs could potentially include costs for, among other things, excavating soil, implementation of institutional controls, and the construction, operation and maintenance of engineering controls.

Clean Water Act (CWA) Section 316(b) Rule

The EPA’s CWA Section 316(b) rule establishes requirements for the design and operation of cooling water intake structures at existing power plants and industrial facilities with a design flow of more than two million gallons of water per day.

In June 2016, the NJDEP issued a final New Jersey Pollutant Discharge Elimination System permit for Salem. In July 2016, the Delaware Riverkeeper Network (Riverkeeper) filed an administrative hearing request challenging certain conditions of the permit, including the NJDEP’s application of the 316(b) rule. If the Riverkeeper’s challenge is successful, PSEG Power may be required to incur additional costs to comply with 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. The NJDEP granted the hearing request and may schedule a hearing after considering dispositive motions.

Jersey City, New Jersey Subsurface Feeder Cable Matter

In 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. The impacted cable was repaired in September 2017. A federal response was initially led by the U.S. Coast Guard. The U.S. Coast Guard transitioned control of the federal response to the EPA, and the EPA ended the federal response to the matter in 2018. The investigation of small amounts of residual dielectric fluid 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.

The lawsuit in federal court to determine ultimate responsibility for the costs to address the leak among PSE&G, Con Edison and NADC has been resolved and is now dismissed.

BGS, BGSS and ZECs

Each year, PSE&G obtains its electric supply requirements through annual New Jersey BGS auctions for two categories of customers that choose not to purchase electric supply from third-party suppliers. The first category 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 Agreements with the winners of these RSCP and CIEP BGS auctions to purchase BGS for PSE&G’s load requirements. The winners of the RSCP and CIEP auctions are responsible for fulfilling all the requirements of a PJM load-serving entity including the provision of capacity, energy, ancillary services 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, 2024 is $378.21 per MW-day, replacing the BGS-CIEP auction year price ending May 31, 2024 of $330.72 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:

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	Auction Year
	2021	2022	2023	2024
36-Month Terms Ending	May 2024	May 2025	May 2026	May 2027	(A)
Load (MW)	2,900	2,800	2,800	2,900
$ per MWh	$64.80	$76.30	$93.11	$80.88

(A)Prices set in the 2024 BGS auction will become effective on June 1, 2024 when the 2021 BGS auction agreements expire.

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 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 24. 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 2026 and a significant portion through 2027 at Salem, Hope Creek and Peach Bottom.

PSEG Power has various multi-year contracts for natural gas and firm transportation and storage capacity for natural gas that are primarily used to meet its obligations to PSE&G.

As of December 31, 2023, the total minimum purchase requirements included in these commitments were as follows:



Fuel Type	PSEG Power’s Share of Commitments through 2028
	Millions
Nuclear Fuel
Uranium	$	392
Enrichment	$	344
Fabrication	$	185
Natural Gas	$	1,329

Pending FERC Matters

FERC 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 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 allegations. PSE&G has the opportunity to respond to these preliminary findings. The matter is pending and the investigation is ongoing. PSE&G is unable to predict the outcome or estimate the range of possible loss related to this matter; however, depending on the success of PSE&G’s factual and legal arguments, the potential financial and other penalties that PSE&G may incur could be material to PSEG’s and PSE&G’s results of operations and financial condition.

BPU Audit of PSE&G

In 2020, the BPU ordered the commencement of a comprehensive affiliate and management audit of PSE&G. It has been more than ten years since the BPU last conducted a management and affiliate audit of this kind of PSE&G, which is initiated

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periodically as required by New Jersey statutes/regulations. Phase 1 of the audit reviews affiliate relations and cost allocation between PSE&G and its affiliates, including an analysis of the relationship between PSE&G and PSEG Energy Resources & Trade, LLC, a wholly owned subsidiary of PSEG Power over the past ten years, and between PSE&G and PSEG LI. Phase 2 is a comprehensive management audit, which addresses, 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 late May 2021. The BPU Audit Staff submitted the final audit report to the BPU in June 2023. The BPU is currently considering public comments on the audit report and has not yet determined which audit recommendations it will require PSE&G to implement. It is not possible at this time to predict the outcome of this matter.

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.

Nuclear Insurance Coverages and Assessments

PSEG Power is a member of the joint underwriting association, American Nuclear Insurers (ANI), which provides nuclear liability insurance coverage at the Salem and Hope Creek site and the Peach Bottom site. The ANI policies are designed to satisfy the financial protection requirements outlined in the Price-Anderson Act, which sets the limit of liability for claims that could arise from an incident involving any licensed nuclear facility in the United States. The limit of liability per incident per site is composed of primary and excess layers. As of December 31, 2023, nuclear sites were required to purchase $450 million of primary liability coverage for each site through ANI. This coverage increased to $500 million effective January 1, 2024. The primary layer is supplemented by an excess layer, which is an industry self-insurance pool. In the event a nuclear site, which is part of the industry self-insurance pool, has a claim that exceeds the primary layer, each licensee would be assessed a prorated share of the excess layer. The excess layer limit is $15.8 billion. PSEG Power’s maximum aggregate assessment per incident is $522 million based on PSEG Power’s ownership interests in Salem, Hope Creek and Peach Bottom and its maximum aggregate annual assessment per incident is $78 million. If the damages exceed the limit of liability, Congress could impose further revenue-raising measures on the nuclear industry to pay claims. Further, a decision by the U.S. Supreme Court, not involving PSEG Power, held that the Price-Anderson Act did not preclude punitive damage awards based on state law claims.

PSEG Power is also a member of an industry mutual insurance company, Nuclear Electric Insurance Limited (NEIL), which provides the property, decontamination and decommissioning liability insurance at the Salem and Hope Creek site and the Peach Bottom site. NEIL also provides replacement power coverage through its accidental outage policy. NEIL policies may make retrospective premium assessments in the case of adverse loss experience. The current maximum aggregate annual retrospective premium obligation for PSEG Power is approximately $48 million. NEIL requires its members to maintain an

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investment grade credit rating or to ensure collectability of their annual retrospective premium obligation by providing a financial guarantee, letter of credit, deposit premium, or some other means of assurance. Certain provisions in the NEIL policies provide that the insurer may suspend coverage with respect to all nuclear units on a site without notice if the NRC suspends or revokes the operating license for any unit on that site, issues a shutdown order with respect to such unit or issues a confirmatory order keeping such unit down.

The ANI and NEIL policies all include coverage for claims arising out of acts of terrorism. However, NEIL policies are subject to an industry aggregate limit of $3.24 billion plus such additional amounts as NEIL recovers for such losses from reinsurance, indemnity and any other source applicable to such losses.

Note 14. Debt and Credit Facilities

Long-Term Debt



			As of December 31,
		Maturity	2023		2022
			Millions
PSEG



Senior Notes:
0.84%		2023	$	—	$	750
2.88%		2024	750		750
0.80%		2025	550		550
5.85%		2027	700		700
5.88%		2028	600		—
1.60%		2030	550		550
8.63%	(A)	2031	96		96
2.45%		2031	750		750
6.13%		2033	400		—
Total Senior Notes			4,396		4,146
Principal Amount Outstanding			4,396		4,146
Amounts Due Within One Year			(750)		(750)
Net Unamortized Discount and Debt Issuance Costs			(25)		(22)
Total Long-Term Debt of PSEG			$	3,621	$	3,374

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		As of December 31,
	Maturity	2023		2022
		Millions
PSE&G
First and Refunding Mortgage Bonds (B):
8.00%	2037	$	7	$	7
5.00%	2037	8		8
Total First and Refunding Mortgage Bonds		15		15
Medium-Term Notes (B):
2.38%	2023	—		500
3.25%	2023	—		325
3.75%	2024	250		250
3.15%	2024	250		250
3.05%	2024	250		250
3.00%	2025	350		350
0.95%	2026	450		450
2.25%	2026	425		425
3.00%	2027	425		425
3.70%	2028	375		375
3.65%	2028	325		325
3.20%	2029	375		375
2.45%	2030	300		300
1.90%	2031	425		425
3.10%	2032	500		500
4.90%	2032	400		400
4.65%	2033	500		—
5.20%	2033	500		—
5.25%	2035	250		250
5.70%	2036	250		250
5.80%	2037	350		350
5.38%	2039	250		250
5.50%	2040	300		300
3.95%	2042	450		450
3.65%	2042	350		350
3.80%	2043	400		400
4.00%	2044	250		250
4.05%	2045	250		250
4.15%	2045	250		250
3.80%	2046	550		550
3.60%	2047	350		350
4.05%	2048	325		325
3.85%	2049	375		375
3.20%	2049	400		400
3.15%	2050	300		300
2.70%	2050	375		375
2.05%	2050	375		375
3.00%	2051	450		450
5.13%	2053	400		—
5.45%	2053	400		—
Total MTNs		13,750		12,775
Principal Amount Outstanding		13,765		12,790
Amounts Due Within One Year		(750)		(825)
Net Unamortized Discount and Selling Expense		(102)		(94)
Total Long-Term Debt of PSE&G		$	12,913	$	11,871

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		As of December 31,
	Maturity	2023		2022
		Millions
PSEG Power
Term Loan:
Variable Rate	2025	$	1,250	$	1,250
Total Term Loan		1,250		1,250

Total Long-Term Debt of PSEG Power		$	1,250	$	1,250

(A)In December 2020, PSEG issued $96 million principal amount of 8.63% Senior Notes due 2031 to holders of a like principal amount of 8.63% Senior Notes due 2031 originally issued by PSEG Power who validly tendered their notes pursuant to an offer to exchange. Upon consummation of the offer to exchange, the PSEG Power notes accepted in the exchange were cancelled. The transaction resulted in a non-cash financing activity for both PSEG and PSEG Power.

(B)Secured by essentially all property of PSE&G pursuant to its First and Refunding Mortgage.

Long-Term Debt Maturities

The aggregate principal amounts of maturities for each of the five years following December 31, 2023 are as follows:



Year	PSEG		PSE&G		PSEG Power		Total
	Millions
2024	$	750	$	750	$	—	$	1,500
2025	550		350		1,250		2,150
2026	—		875		—		875
2027	700		425		—		1,125
2028	600		700		—		1,300
Thereafter	1,796		10,665		—		12,461
Total	$	4,396	$	13,765	$	1,250	$	19,411

Long-Term Debt Financing Transactions

During 2023, the following long-term debt transactions occurred:

PSEG

•issued $600 million of 5.88% Senior Notes due October 2028,

•issued $400 million of 6.13% Senior Notes due October 2033, and

•retired $750 million of 0.84% Senior Notes at maturity.

PSE&G

•issued $500 million of 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,

•issued $500 million of 5.20% Secured Medium-Term Notes, Series P, due August 2033,

•issued $400 million of 5.45% Secured Medium-Term Notes, Series P, due August 2053,

•retired $500 million of 2.38% Secured Medium-Term Notes, Series I, at maturity, and

•retired $325 million of 3.25% Secured Medium-Term Notes, Series M, at maturity.

Short-Term Liquidity

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meet its short-term liquidity requirements. Each commercial paper program is fully back-stopped by its own separate credit facility.

The commitments under the $4.0 billion credit facilities are provided by a diverse bank group. As of December 31, 2023, the total available credit capacity was $3.4 billion.

As of December 31, 2023, no single institution represented more than 10% of the total commitments in the credit facilities.

As of December 31, 2023, PSEG’s liquidity position, including credit facilities and access to external financing, was expected to be sufficient to meet its projected stressed requirements 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 December 31, 2023 were as follows:



	As of December 31, 2023
Company/Facility	Total Facility		Usage (B)		Available Liquidity		Expiration Date	Primary Purpose
	Millions
PSEG
Revolving Credit Facility (A)	$	1,500	$	27	$	1,473	Mar 2027	Commercial Paper Support/Funding/Letters of Credit
Total PSEG	$	1,500	$	27	$	1,473
PSE&G
Revolving Credit Facility	$	1,000	$	445	$	555	Mar 2027	Commercial Paper Support/Funding/Letters of Credit
Total PSE&G	$	1,000	$	445	$	555
PSEG Power
Revolving Credit Facility (A)	$	1,250	$	39	$	1,211	Mar 2027	Funding/Letters of Credit
Letter of Credit Facility	75		66		9		Apr 2026	Letters of Credit
Letter of Credit Facility	200		83		117		Sept 2024	Letters of Credit
Total PSEG Power	$	1,525	$	188	$	1,337
Total (C)	$	4,025	$	660	$	3,365

(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 December 31, 2023, PSEG had $25 million outstanding at a weighted average interest rate of 5.60%. PSE&G had $425 million Commercial Paper outstanding at a weighted average interest rate of 5.57%.

(C)Amounts do not include uncommitted credit facilities.

PSEG Power has an uncommitted credit facility for $100 million, which can be utilized for letters of credit. A subsidiary of PSEG Power has an uncommitted credit facility for $150 million, which can be utilized for cash collateral postings. As of December 31, 2023, there was an immaterial amount outstanding under these facilities.

Debt Covenants

PSEG Power’s existing credit agreements contain covenants restricting the ability of PSEG Power and its subsidiaries that guarantee its indebtedness from consummating certain mergers, consolidations or asset sales.

Short-Term Loans

Fair Value of Debt

The estimated fair values, carrying amounts and methods used to determine the fair values of long-term debt as of

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December 31, 2023 and 2022 are included in the following table and accompanying notes as of December 31, 2023 and 2022. See Note 17. Fair Value Measurements for more information on fair value guidance and the hierarchy that prioritizes the inputs to fair value measurements into three levels.



	December 31, 2023				December 31, 2022
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	Millions
Long-Term Debt:
PSEG (A)	$	4,371	$	4,240	$	4,124	$	3,808
PSE&G (A)	13,663		12,460		12,696		11,106
PSEG Power (B)	1,250		1,250		1,250		1,250
Total Long-Term Debt	$	19,284	$	17,950	$	18,070	$	16,164

(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).

Note 15. Schedule of Consolidated Capital Stock



	As of December 31,
	Outstanding Shares		Book Value
	2023	2022	2023		2022
	Millions
PSEG Common Stock (no par value) (A)
Authorized 1,000 shares	498	497	$	3,639	$	3,688

(A)PSEG did not issue any new shares under the Dividend Reinvestment and Stock Purchase Plan or the Employee Stock Purchase Plan (ESPP) in 2023 or 2022.

As of December 31, 2023, PSE&G had an aggregate of 7.5 million shares of $100 par value and 10 million shares of $25 par value Cumulative Preferred Stock, which were authorized and unissued and which, upon issuance, may or may not provide for mandatory sinking fund redemption.

Note 16. 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 NPNS cash flow hedge and fair value hedge accounting. PSEG uses interest rate swaps and other derivatives, which are designated and qualifying as cash flow or fair value hedges. PSEG Power 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 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 to changes in the market price of electricity, 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

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expected generation. PSEG Power also uses derivatives to hedge a portion of its anticipated BGSS obligations with PSE&G. For additional information see Note 13. Commitments and Contingent Liabilities. Additionally, prospective changes in the fair market value of these derivative contracts are recorded in earnings.

Interest Rates

PSEG, PSE&G and 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. PSEG, PSE&G and PSEG Power may use a mix of fixed and floating rate debt, interest rate swaps and interest rate 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 to variable-rate debt instruments.

As of December 31, 2023, PSEG had interest rate hedges outstanding totaling $1.4 billion which were executed to convert $900 million of PSEG Power’s $1.25 billion variable rate term loan due March 2025 and PSEG’s $500 million variable rate term loan due April 2024 into fixed rate loans. The fair value of these hedges was a net $5 million and $1 million as of December 31, 2023 and 2022, respectively.

In the third quarter of 2023, PSEG entered into interest rate treasury locks totaling $800 million to fix the interest rate for a portion of an anticipated $1 billion long-term debt issuance that occurred in October 2023. The settlement payment of $17 million for these treasury locks was recorded in Accumulated Other Comprehensive Income (Loss) and will be amortized into earnings to match the term and timing of the hedged debt.

In the fourth quarter of 2023, PSEG entered into interest rate treasury locks totaling $600 million to fix the interest rate for a portion of an anticipated long-term debt issuance. As of December 31, 2023, these treasury locks had a fair value of $(16) million.

The Accumulated Other Comprehensive Income (Loss) (after tax) related to outstanding and terminated interest rate derivatives designated as cash flow hedges was $3 million and $(3) million as of December 31, 2023 and December 31, 2022, respectively. The after-tax unrealized gains on these hedges expected to be reclassified to earnings during the next 12 months are $3 million.

Fair Values of Derivative Instruments

The following are the fair values of derivative instruments on the 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 Consolidated Balance Sheets of PSEG. For additional information see Note 17. 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 did not have any collateral posted or received as of December 31, 2023 and 2022. The following tabular disclosure does not include the offsetting of trade receivables and payables.

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	As of December 31, 2023
	PSEG		PSEG Power						Consolidated
	Cash Flow Hedges		Not Designated
Balance Sheet Location	Interest Rate Derivatives		Energy- Related Contracts		Netting (A)		Total PSEG Power		Total Derivatives
	Millions
Derivative Contracts
Current Assets	$	6	$	912	$	(806)	$	106	$	112
Noncurrent Assets	—		440		(411)		29		29
Total Mark-to-Market Derivative Assets	$	6	$	1,352	$	(1,217)	$	135	$	141
Derivative Contracts
Current Liabilities	$	(16)	$	(890)	$	820	$	(70)	$	(86)
Noncurrent Liabilities	(1)		(424)		419		(5)		(6)
Total Mark-to-Market Derivative (Liabilities)	$	(17)	$	(1,314)	$	1,239	$	(75)	$	(92)
Total Net Mark-to-Market Derivative Assets (Liabilities)	$	(11)	$	38	$	22	$	60	$	49



	As of December 31, 2022
	PSEG		PSEG Power						Consolidated
	Cash Flow Hedges		Not Designated
Balance Sheet Location	Interest Rate Derivatives		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 cash collateral. All cash collateral (received) posted that has been allocated to derivative positions, where the right of offset exists, has been offset on the Consolidated Balance Sheets. As of December 31, 2023 and 2022, PSEG Power had net cash collateral payments to counterparties of $113 million and $1,521 million, respectively. Of these net cash collateral (receipts) payments, $22 million as of December 31, 2023 and $1,111 million as of December 31, 2022 were netted against the corresponding net derivative contract positions. Of the $22 million as of December 31, 2023, $(1) million was netted against current assets, $15 million was netted against current liabilities and $8 million was netted against noncurrent liabilities. Of the $1,111 million as of December 31, 2022, $616 million was netted against current liabilities and $495 million was netted 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 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

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Power would represent a two level downgrade from its current Moody’s and S&P 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 $77 million and $190 million as of December 31, 2023 and 2022, respectively. As of December 31, 2023 and 2022, PSEG Power had the contractual right of offset of $3 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 $74 million and $149 million as of December 31, 2023 and 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 Consolidated Statements of Operations and on Accumulated Other Comprehensive Loss (AOCL) of derivative instruments designated as cash flow hedges for the years ended December 31, 2023, 2022 and 2021.



	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
Derivatives in Cash Flow Hedging Relationships	Years Ended December 31,							Years Ended December 31,
	2023		2022		2021			2023		2022		2021
	Millions							Millions
Interest Rate Derivatives	$	13	$	—	$	—	Interest Expense	$	5	$	(5)	$	(4)
Total	$	13	$	—	$	—		$	5	$	(5)	$	(4)

The effect of interest rate cash flow hedges is recorded in Interest Expense in PSEG’s Consolidated Statement of Operations. The amount of gain (loss) on interest rate hedges reclassified from Accumulated Other Comprehensive Income (Loss) into income was $3 million, $(3) million and $(3) million after tax as of December 31, 2023, 2022 and 2021, respectively.

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



Accumulated Other Comprehensive Income (Loss)	Pre-Tax		After-Tax
	Millions
Balance as of December 31, 2021	$	(9)	$	(6)
Loss Recognized in AOCI	—		—
Less: Loss Reclassified into Income	5		3
Balance as of December 31, 2022	$	(4)	$	(3)
Gain Recognized in AOCI	13		9
Less: Gain Reclassified into Income	(5)		(3)
Balance as of December 31, 2023	$	4	$	3

The following shows the effect on the Consolidated Statements of Operations of derivative instruments not designated as hedging instruments or as NPNS for the years ended December 31, 2023, 2022 and 2021. 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.

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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
		Years Ended December 31,
		2023		2022		2021
		Millions
Energy-Related Contracts	Operating Revenues	$	1,567	$	(1,748)	$	(993)
Energy-Related Contracts	Energy Costs	—		2		126
Total		$	1,567	$	(1,746)	$	(867)

The following table summarizes the net notional volume purchases/(sales) of open derivative transactions by commodity as of December 31, 2023 and 2022.



		As of December 31,
Type	Notional	2023	2022
		Millions
Natural Gas	Dekatherm	66	49
Electricity	MWh	(60)	(60)
Financial Transmission Rights	MWh	19	24
Interest Rate Derivatives	U.S. Dollars	2,000	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 PSEG’s financial condition, results of operations or net cash flows.

As of December 31, 2023, nearly 100% of the net credit exposure for PSEG Power’s wholesale operations was with investment grade counterparties and there was only one counterparty with credit exposure that was greater than 10% of the total. This credit exposure was with PSE&G, which eliminates in consolidation. See Note 24. Related-Party Transactions for additional information.

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 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 December 31, 2023, PSEG held parental guarantees, letters of credit and cash as security. PSE&G’s BGS suppliers’ credit exposure is calculated each business day. As of December 31, 2023, PSE&G had no unsecured mark-to-market credit exposure with 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.

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Note 17. 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 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. These consist primarily of certain electric load 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 respective assets and (liabilities) measured at fair value on a recurring basis as of December 31, 2023 and December 31, 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.

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	Recurring Fair Value Measurements as of December 31, 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)	$	20	$	—	$	20	$	—	$	—
Derivative Contracts:
Energy-Related Contracts (B)	$	135	$	(1,217)	$	13	$	1,339	$	—
Interest Rate Derivatives (C)	$	6	$	—	$	—	$	6	$	—
NDT Fund (D)
Equity Securities	$	1,310	$	—	$	1,310	$	—	$	—
Debt Securities—U.S. Treasury	$	293	$	—	$	—	$	293	$	—
Debt Securities—Govt Other	$	398	$	—	$	—	$	398	$	—
Debt Securities—Corporate	$	522	$	—	$	—	$	522	$	—

Rabbi Trust (D)
Equity Securities	$	18	$	—	$	18	$	—	$	—
Debt Securities—U.S. Treasury	$	59	$	—	$	—	$	59	$	—
Debt Securities—Govt Other	$	32	$	—	$	—	$	32	$	—
Debt Securities—Corporate	$	70	$	—	$	—	$	70	$	—

Liabilities:
Derivative Contracts:
Energy-Related Contracts (B)	$	(75)	$	1,239	$	(1)	$	(1,311)	$	(2)
Interest Rate Derivatives (C)	$	(17)	$	—	$	—	$	(17)	$	—
PSE&G
Assets:
Cash Equivalents (A)	$	20	$	—	$	20	$	—	$	—


Rabbi Trust (D)
Equity Securities	$	3	$	—	$	3	$	—	$	—
Debt Securities—U.S. Treasury	$	11	$	—	$	—	$	11	$	—
Debt Securities—Govt Other	$	6	$	—	$	—	$	6	$	—
Debt Securities—Corporate	$	12	$	—	$	—	$	12	$	—

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	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 Derivatives (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 Derivatives	$	(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.

(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.

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” for more information on the utilization of unobservable inputs.

(C)Interest rate derivatives 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.

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(D)As of December 31, 2023 and 2022, the fair value measurement table excludes cash and foreign currency of $1 million and $2 million, respectively, in the NDT Fund. 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 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 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 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, dollar-denominated debt securities and government securities. The funds’ net asset value is priced and published daily. The Rabbi Trust’s Russell 3000 index fund is valued based on quoted prices in an active market and can be redeemed daily without restriction.

Level 2—NDT and Rabbi Trust fixed income securities include investment grade corporate bonds, collateralized mortgage obligations, 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. 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. See Note 16. 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 Level 3 because the model inputs generally are not observable. PSEG considers credit and 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 non-performance risk by counterparty. The impacts of credit and non-performance risk were not material to the financial statements.

As of December 31, 2023, PSEG carried $2.8 billion of net assets that were measured at fair value on a recurring basis, of which $2 million of net liabilities were measured using unobservable inputs and classified as Level 3 within the fair value hierarchy and are considered immaterial.

As of December 31, 2022, PSEG carried $2.7 billion of net assets that were measured at fair value on a recurring basis, of which $45 million of net liabilities were measured using unobservable inputs and classified as Level 3 within the fair value hierarchy and are considered immaterial.

There were no transfers in 2023 and 2022 to or from Level 3.

Note 18. Stock Based Compensation

PSEG’s 2021 Long-Term Incentive Plan (2021 LTIP), approved by shareholders on April 20, 2021 and the Amended and Restated 2004 Long-Term Incentive Plan ((2004 LTIP) under which no new grants have been made effective April 20, 2021), are broad-based equity compensation programs that provide for grants of various long-term incentive compensation awards, such as stock options, stock appreciation rights, performance share units (PSUs), restricted stock, restricted stock units (RSUs), cash awards or any combination thereof. The types of long-term incentive awards that have been granted under the LTIP are non-qualified options to purchase shares of PSEG’s common stock, restricted stock unit awards and performance share unit awards. The type of equity award that is granted and the details of that award may vary from time to time and is subject to the approval of the Organization and Compensation Committee of PSEG’s Board of Directors (O&CC), the LTIP’s administrative committee.

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The 2021 LTIP currently provides for the issuance of equity awards with respect to 8 million shares of common stock. As of December 31, 2023, approximately 7 million shares were available for future awards under the 2021 LTIP.

In addition, on April 20, 2021 shareholders approved the PSEG 2021 Equity Compensation Plan for Outside Directors (2021 BOD Plan) and the PSEG 2007 Equity Compensation Plan for Outside Directors (2007 BOD Plan) was closed to new awards.

Under the 2021 BOD Plan, the only equity instrument which may be granted are RSUs and the Board member must defer the award until they have achieved their stock ownership requirement.

Stock Options

Under the 2021 LTIP, non-qualified options to acquire shares of PSEG common stock may be granted to officers and other key employees selected by the O&CC. No options have been granted since 2009.

RSUs

Under both the 2021 LTIP and 2004 LTIP (LTIPs), PSEG has granted RSU awards to officers and other key employees. These awards, which are bookkeeping entries only, are subject to risk of forfeiture until vested by continued employment. Until distributed, the units are credited with dividend equivalent units (DEUs) proportionate to the dividends paid on PSEG common stock. Distributions are made in shares of common stock. The RSU grants for 2023 and 2022 generally vest at the end of three years. Vesting may be accelerated (pro-rated basis or full vesting) upon certain events such as change-in-control, retirement, disability or death.

PSUs

Under the LTIPs, PSEG has granted PSUs to officers and other key employees. These provide for distribution in shares of PSEG common stock based on achievement of certain goals over a performance period of three years. Following the end of the performance period, the payout varies from 0% to 200% of the number of PSUs granted depending on PSEG’s performance with respect to those goals. The PSUs are credited with DEUs proportionate to the dividends paid on PSEG common stock. Distributions are made in shares of common stock. Vesting may be accelerated on a pro-rated basis for the period of the employee’s service during the performance period as a result of certain events, such as change-in-control, retirement, death or disability.

Stock-Based Compensation

PSEG recognizes compensation expense for RSUs over the vesting period based on the grant date fair value of the shares, which is equal to the closing market price of PSEG’s common stock on the date of the grant.

PSEG recognizes compensation expense for the total shareholder return (TSR) target for its PSU awards based on the grant date fair values of the award, which are determined using the Monte Carlo model. The following table provides the assumptions used to calculate the grant date fair value of the TSR portion of the PSU awards for 2023, 2022 and 2021:



Grant Date	Risk-Free Interest Rate	Volatility

February 14, 2023	4.24%	25.09%
February 15, 2022	1.76%	27.34%
February 16, 2021	0.22%	27.31%

The accrual of compensation cost is based on the probable achievement of the performance conditions, which result in a payout from 0% to 200% of the initial grant. PSEG recognizes compensation expense for all other components of its PSUs based on the grant date fair value of the awards, which is equal to the market price of PSEG’s common stock on the date of the grant. The accrual during the year of grant is estimated at 100% of the original grant. Such accrual may be adjusted to reflect the actual outcome.



	2023		2022		2021
	Millions
Compensation Cost included in O&M Expense	$	18	$	29	$	28
Income Tax Benefit Recognized in Consolidated Statement of Operations	$	5	$	8	$	8

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For each of the years 2023, 2022 and 2021, PSEG also recorded excess tax benefits of $22 million, $2 million and $2 million, respectively.

PSEG recognizes compensation cost of awards issued over the shorter of the original vesting period or the period beginning on the date of grant and ending on the date an individual is eligible for retirement and the award vests.

RSUs

Changes in RSUs for the year ended December 31, 2023 are summarized as follows:



	Shares	Weighted Average Grant Date Fair Value		Weighted Average Remaining Years Contractual Term	Aggregate Intrinsic Value
Non-vested as of January 1, 2023	216,240	$	61.02
Granted	286,059	$	61.44
Vested	213,504	$	60.61
Canceled/Forfeited	25,614	$	61.21
Non-vested as of December 31, 2023	263,181	$	61.79	1.2	$	16,093,498

The weighted average grant date fair value per share for RSUs during the years ended December 31, 2023, 2022 and 2021 was $61.44, $64.44 and $58.02 per share, respectively.

The total intrinsic value of RSUs distributed during the years ended December 31, 2023, 2022 and 2021 was $54 million, $19 million and $17 million, respectively.

As of December 31, 2023, there was approximately $7 million of unrecognized compensation cost related to the RSUs, which is expected to be recognized over a weighted average period of 1.2 years. DEUs of 29,174 accrued on the RSUs during the year.

PSUs

Changes in PSUs for the year ended December 31, 2023 are summarized as follows:



	Shares	Weighted Average Grant Date Fair Value		Weighted Average Remaining Years Contractual Term	Aggregate Intrinsic Value
Non-vested as of January 1, 2023	397,010	$	67.65
Granted	388,658	$	67.99
Vested	253,289	$	66.81
Canceled/Forfeited	49,963	$	68.20
Non-vested as of December 31, 2023	482,416	$	68.31	1.6	$	29,499,703

The weighted average grant date fair value per share for PSUs during the years ended December 31, 2023, 2022 and 2021 was $67.99, $68.90 and $65.57 per share, respectively.

The total intrinsic value of PSUs distributed during the years ended December 31, 2023, 2022 and 2021 was $95 million, $18 million and $28 million, respectively.

As of December 31, 2023, there was approximately $25 million of unrecognized compensation cost related to the PSUs, which is expected to be recognized over a weighted average period of 1.6 years. DEUs of 40,329 accrued on the PSUs during the year.

Outside Directors

Under the closed 2007 BOD Plan and the new 2021 BOD Plan, annually, on the first business day of May, each non-employee member of the Board of Directors is awarded stock units based on the amount of annual compensation to be paid at the closing price of PSEG common stock on that date. DEUs are credited quarterly and distributions will occur as specified by their election in accordance with the provisions of the BOD Plan.

The fair value of these awards is recorded as compensation expense in the Consolidated Statements of Operations. Compensation expense for the plan was $2 million for the years ended December 31, 2023 and 2022, and immaterial for the year ended December 31, 2021.

ESPP

PSEG maintains an ESPP for all eligible employees of PSEG and its subsidiaries. Under the ESPP, shares of PSEG common stock may be purchased at 95% of the fair market value for represented employees and 90% for non-represented employees

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through payroll deductions. Dividends are to be paid out in cash unless the participant elects the dividends to be reinvested at fair market price. All employees are required to hold the shares purchased under the ESPP for at least three months from the purchase date. In any year, employees may purchase shares having a value not exceeding 10% of their base pay. Compensation expense recognized under this program was $2 million for each of the years ended December 31, 2023, 2022 and 2021.

During the years ended December 31, 2023, 2022 and 2021, employees purchased 339,807 shares, 321,429 shares and 326,634 shares, respectively, at an average price of $55.84, $57.72 and $56.87 per share, respectively. As of December 31, 2023, 1.2 million shares were available for future issuance under this plan.

Note 19. Net Other Income (Deductions)



	PSE&G		PSEG Power & Other (A)		Consolidated
	Millions
Year Ended December 31, 2023
NDT Fund Interest and Dividends	$	—	$	68	$	68
AFUDC	60		—		60
Solar Loan Interest	7		—		7
Other Interest	12		34		46
Donations	(1)		—		(1)

Other	2		(10)		(8)
Total Net Other Income (Deductions)	$	80	$	92	$	172
Year Ended December 31, 2022
NDT Fund Interest and Dividends	$	—	$	62	$	62
AFUDC	65		—		65
Solar Loan Interest	10		—		10
Other Interest	9		12		21
Donations	—		(1)		(1)
Purchases of Tax Losses under New Jersey Technology Tax Benefit Transfer Program	—		(27)		(27)
Other	4		(10)		(6)
Total Net Other Income (Deductions)	$	88	$	36	$	124
Year Ended December 31, 2021
NDT Fund Interest and Dividends	$	—	$	59	$	59
AFUDC	71		—		71
Solar Loan Interest	13		—		13
Other Interest	1		6		7
Donations	(1)		(21)		(22)
Purchases of Tax Losses under New Jersey Technology Tax Benefit Transfer Program	—		(19)		(19)
Other	4		(15)		(11)
Total Net Other Income (Deductions)	$	88	$	10	$	98

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

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Note 20. 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:



	Years Ended December 31,
PSEG	2023			2022			2021
	Millions
Net Income (Loss)	$	2,563		$	1,031		$	(648)
Income Taxes:
Operating Income:
Current Expense (Benefit):
Federal	$	144		$	262		$	407
State	19			(30)			(3)
Total Current	163			232			404
Deferred Expense (Benefit):
Federal	109			(335)			(700)
State	253			80			(136)
Total Deferred	362			(255)			(836)
ITC	(7)			(6)			(9)
Total Income Tax Expense (Benefit)	$	518		$	(29)		$	(441)
Pre-Tax Income (Loss)	$	3,081		$	1,002		$	(1,089)
Tax Computed at Statutory Rate @ 21%	$	647		$	210		$	(229)
Increase (Decrease) Attributable to Flow-Through of Certain Tax Adjustments:
State Income Taxes (net of federal income tax)	215			41			(109)
Uncertain Tax Positions	(14)			(22)			19
NDT Fund	26			(22)			23
Plant-Related Items	(7)			(6)			(7)
Tax Credits	(10)			(10)			29
Audit Settlement	(7)			—			(8)
Leasing Activities	(22)			—			(1)
GPRC-CEF-EE	(52)			(37)			(13)
TAC	(232)			(193)			(171)
Bad Debt Flow-Through	(9)			(1)			27
Other	(17)			11			(1)
Subtotal	(129)			(239)			(212)
Total Income Tax Expense (Benefit)	$	518		$	(29)		$	(441)
Effective Income Tax Rate	16.8		%	(2.9)		%	40.5		%

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The following is an analysis of deferred income taxes for PSEG:



	As of December 31,
PSEG	2023		2022
	Millions
Deferred Income Taxes
Assets:
Regulatory Liability Excess Deferred Tax	$	339	$	390
OPEB	58		74
Bad Debt	57		66
Corporate Alternative Minimum Tax (CAMT) Credit Carryforward	44		—
Operating Leases	42		42
Other	129		379
Total Assets	$	669	$	951

Liabilities:
Plant-Related Items	$	4,850	$	4,663
New Jersey Corporate Business Tax	1,284		1,009
Leasing Activities	35		99
AROs and NDT Fund	250		161
Taxes Recoverable Through Future Rates (net)	201		149
Pension Costs	189		164
Operating Leases	38		37
Other	430		324
Total Liabilities	$	7,277	$	6,606
Summary of Accumulated Deferred Income Taxes:
Net Deferred Income Tax Liabilities	$	6,608	$	5,655
ITC	63		70
Net Total Deferred Income Taxes and ITC	$	6,671	$	5,725

The deferred tax effect of certain assets and liabilities is presented in the table above net of the deferred tax effect associated with the respective regulatory deferrals.

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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:



	Years Ended December 31,
PSE&G	2023			2022			2021
	Millions
Net Income	$	1,515		$	1,565		$	1,446
Income Taxes:
Operating Income:
Current Expense (Benefit):
Federal	$	127		$	130		$	208
State	4			—			1
Total Current	131			130			209
Deferred Expense (Benefit):
Federal	(113)			(17)			(33)
State	149			159			153
Total Deferred	36			142			120
ITC	(7)			(5)			(5)
Total Income Tax Expense	$	160		$	267		$	324
Pre-Tax Income	$	1,675		$	1,832		$	1,770
Tax Computed at Statutory Rate @ 21%	$	352		$	385		$	372
Increase (Decrease) Attributable to Flow-Through of Certain Tax Adjustments:
State Income Taxes (net of federal income tax)	121			126			122
Uncertain Tax Positions	(9)			2			2
Plant-Related Items	(7)			(6)			(7)
Tax Credits	(9)			(9)			(8)
GPRC-CEF-EE	(52)			(37)			(13)
TAC	(232)			(193)			(171)
Bad Debt Flow-Through	(9)			(1)			27
Other	5			—			—
Subtotal	(192)			(118)			(48)
Total Income Tax Expense	$	160		$	267		$	324
Effective Income Tax Rate	9.6		%	14.6		%	18.3		%

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The following is an analysis of deferred income taxes for PSE&G:



	As of December 31,
PSE&G	2023		2022
	Millions
Deferred Income Taxes
Assets:
Regulatory Liability Excess Deferred Tax	$	339	$	390
OPEB	28		42
CAMT Credit Carryforward	106		—
Bad Debt	57		66
Operating Leases	22		19
Other	60		56
Total Assets	$	612	$	573
Liabilities:
Plant-Related Items	$	4,396	$	4,174
New Jersey Corporate Business Tax	1,160		1,011
Pension Costs	198		195
Taxes Recoverable Through Future Rates (net)	201		149
Conservation Costs	88		81
Operating Leases	21		18
Other	297		223
Total Liabilities	$	6,361	$	5,851
Summary of Accumulated Deferred Income Taxes:
Net Deferred Income Tax Liabilities	$	5,749	$	5,278
ITC	64		70
Net Total Deferred Income Taxes and ITC	$	5,813	$	5,348

The deferred tax effect of certain assets and liabilities is presented in the table above net of the deferred tax effect associated with the respective regulatory deferrals.

PSEG and PSE&G each provide deferred taxes at the enacted statutory tax rate for all temporary differences between the financial statement carrying amounts and the tax bases of assets and liabilities irrespective of the treatment for rate-making purposes. Management believes that it is probable that the accumulated tax benefits that previously have been treated as a flow-through item to PSE&G customers will be recovered from or refunded to PSE&G’s customers in the future. See Note 6. Regulatory Assets and Liabilities.

The 2018 decrease in the federal tax rate resulted in PSE&G recording excess deferred income taxes. As of December 31, 2023, the balance was approximately $1.3 billion with a Regulatory Liability of approximately $1.8 billion. In 2023, PSE&G returned approximately $323 million of excess deferred income taxes and previously realized and current period deferred income taxes related to tax repair deductions to its customers with a reduction to tax expense of approximately $232 million. The flowback to customers of the excess deferred income taxes and previously realized tax repair deductions resulted in a decrease of approximately $243 million in the Regulatory Liability. The current period tax repair deduction reduces tax expense and revenue and recognizes a Regulatory Asset as PSE&G believes it is probable that the current period tax repair deductions flowed through to the customers will be recovered from customers in the future. See Note 6. Regulatory Assets and Liabilities for additional information.

In March 2020, the federal Coronavirus Aid, Relief, and Economic Security Act (CARES Act) was enacted. Among other provisions, the CARES Act allows a five-year carryback of any net operating loss (NOL) generated in a taxable year beginning after December 31, 2017, and before January 1, 2021.

In April 2020, the IRS issued a private letter ruling to PSE&G concluding that certain excess deferred taxes previously classified as protected should be classified as unprotected. Unprotected excess deferred income taxes are not subject to the normalization rules allowing them to be refunded to customers sooner as agreed to with FERC and the BPU. In July 2020, FERC and the BPU approved PSE&G’s requests to refund these unprotected excess deferred income taxes to customers. FERC

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approved the refund of these unprotected excess deferred income taxes within the 2019 true-up filing. The BPU approved the refund of these unprotected excess deferred income taxes beginning in July 2020 through December 31, 2024.

In July 2020, the IRS issued final and proposed regulations addressing the limitation on deductible business interest expense contained in the Tax Act. These regulations retroactively allow depreciation to be added back in computing the 30% adjusted taxable income (ATI) cap, increasing the amount of interest that can be deducted by unregulated businesses in years before 2022. For 2022 and after, the regulations continue to disallow the addback of depreciation in the computation of ATI, effectively lowering the cap on the amount of deductible business interest and contain special rules in allocating interest between regulated and non-regulated businesses. The portion of PSEG’s and PSEG Power’s business interest expense that was disallowed in 2018 and 2019 under the previously issued proposed regulations will now be deductible in those respective years.

In March 2021, PSEG amended its 2018 federal income tax return to deduct the previously disallowed business interest expense in accordance with the final and proposed regulations issued in July 2020. The 2018 amended return generated a NOL that was carried back to 2013 as provided by the CARES Act. In December 2022, the carryback claim was approved by the IRS, which resulted in a $28 million income statement benefit and the closure of PSEG’s federal tax years through 2018.

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% CAMT, effective in 2023. For 2023, PSEG and PSE&G have recorded its best estimate of the impact of the CAMT. To the extent the CAMT exceeds the regular tax liability, the difference can be indefinitely carried forward to reduce regular tax liability in years that it exceeds the CAMT. PSEG and PSE&G anticipate the excess CAMT will be used in the future and will not result in an impact to PSEG’s or PSE&G’s income statement. Changes to the energy tax credit laws include: effective 2024 through 2032 a new PTC for existing nuclear generation facilities, effective 2025 a new technology neutral energy tax credit, which includes new nuclear units and increases to nuclear generation capacity, and effective 2023 the transferability of the energy tax credits. The PTC is designed to phase down as the nuclear facilities’ gross receipts increase. The PTC can be increased by five times if the prevailing wages rules are met. The PTC rate and phase down amount are subject to the IRS’ determination of annual inflation.

Despite the issuance of proposed regulations and various Notices that provide interim guidance on several provisions of the IRA many aspects of the IRA, including the PTC for existing nuclear generation facilities and the CAMT, remain unclear and are in need of further guidance; therefore, the impact of several provisions of the IRA will have on PSEG's and PSE&G's financial statements is subject to continued evaluation.

The enactment of additional federal or state tax legislation and clarification of previously enacted tax laws could impact PSEG’s and PSE&G’s financial statements.

As of December 31, 2023, PSEG had a $33 million state NOL and PSE&G had a $71 million New Jersey Corporate Business Tax NOL that are both expected to be fully realized in the future.

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PSEG recorded the following amounts related to its unrecognized tax benefits, which were primarily comprised of amounts recorded for PSE&G and PSEG’s other subsidiaries:



2023	PSEG		PSE&G
	Millions
Total Amount of Unrecognized Tax Benefits as of January 1, 2023	$	130	$	29
Increases as a Result of Positions Taken in a Prior Period	16		2
Decreases as a Result of Positions Taken in a Prior Period	(25)		(12)
Increases as a Result of Positions Taken during the Current Period	—		—
Decreases as a Result of Positions Taken during the Current Period	—		—
Decreases as a Result of Settlements with Taxing Authorities	(10)		(7)
Decreases due to Lapses of Applicable Statute of Limitations	(1)		(1)
Total Amount of Unrecognized Tax Benefits as of December 31, 2023	$	110	$	11
Accumulated Deferred Income Taxes Associated with Unrecognized Tax Benefits	(29)		(7)
Regulatory Asset—Unrecognized Tax Benefits	(2)		(2)
Total Amount of Unrecognized Tax Benefits that if Recognized, would Impact the Effective Tax Rate (including Interest and Penalties)	$	79	$	2



2022	PSEG		PSE&G
	Millions
Total Amount of Unrecognized Tax Benefits as of January 1, 2022	$	192	$	27
Increases as a Result of Positions Taken in a Prior Period	9		2
Decreases as a Result of Positions Taken in a Prior Period	(40)		(2)
Increases as a Result of Positions Taken during the Current Period	1		1
Decreases as a Result of Positions Taken during the Current Period	—		—
Decreases as a Result of Settlements with Taxing Authorities	(28)		—
Decreases due to Lapses of Applicable Statute of Limitations	(4)		1
Total Amount of Unrecognized Tax Benefits as of December 31, 2022	$	130	$	29
Accumulated Deferred Income Taxes Associated with Unrecognized Tax Benefits	(37)		(15)
Regulatory Asset—Unrecognized Tax Benefits	(8)		(8)
Total Amount of Unrecognized Tax Benefits that if Recognized, would Impact the Effective Tax Rate (including Interest and Penalties)	$	85	$	6

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2021	PSEG		PSE&G
	Millions
Total Amount of Unrecognized Tax Benefits as of January 1, 2021	$	147	$	30
Increases as a Result of Positions Taken in a Prior Period	58		8
Decreases as a Result of Positions Taken in a Prior Period	(19)		(12)
Increases as a Result of Positions Taken during the Current Period	6		1
Decreases as a Result of Positions Taken during the Current Period	—		—
Decreases as a Result of Settlements with Taxing Authorities	—		—
Decreases due to Lapses of Applicable Statute of Limitations	—		—
Total Amount of Unrecognized Tax Benefits as of December 31, 2021	$	192	$	27
Accumulated Deferred Income Taxes Associated with Unrecognized Tax Benefits	(76)		(15)
Regulatory Asset—Unrecognized Tax Benefits	(7)		(7)
Total Amount of Unrecognized Tax Benefits that if Recognized, would Impact the Effective Tax Rate (including Interest and Penalties)	$	109	$	5

In 2022, the IRS approved PSEG’s 2018 carryback claim, which resulted in the closure of PSEG’s federal tax years through 2018.

PSEG and its subsidiaries include accrued interest and penalties related to uncertain tax positions required to be recorded as Income Tax Expense in the Consolidated Statements of Operations. Accumulated interest and penalties that are recorded on the Consolidated Balance Sheets on uncertain tax positions were as follows:



	Accumulated Interest and Penalties on Uncertain Tax Positions as of December 31,
	2023		2022		2021
	Millions
PSEG	$	25	$	38	$	31
PSE&G	$	1	$	8	$	9

It is reasonably possible that total unrecognized tax benefits will significantly increase or decrease within the next twelve months due to either agreements with various taxing authorities upon audit, the expiration of the Statute of Limitations, or other pending tax matters. These potential increases or decreases are as follows:



Possible Decrease in Total Unrecognized Tax Benefits	Over the next 12 Months
	Millions
PSEG	$	17
PSE&G	$	2

A description of income tax years that remain subject to examination by material jurisdictions, where an examination has not already concluded are:

PSEG

PSE&G

United States

Federal

2020-2022

N/A

New Jersey

2011-2022

2015-2022

Pennsylvania

2017-2022

2019-2022

Connecticut

2019-2022

N/A

Maryland

2020-2022

N/A

New York

2017-2022

N/A

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Note 21. Accumulated Other Comprehensive Income (Loss), Net of Tax



PSEG	Other Comprehensive Income (Loss)
Accumulated Other Comprehensive Income (Loss)	Cash Flow Hedges		Pension and OPEB Plans		Available-for -Sale Securities		Total
	Millions
Balance as of December 31, 2020	$	(9)	$	(545)	$	50	$	(504)
Current Period Other Comprehensive Income (Loss)
Other Comprehensive Income (Loss) before Reclassifications	—		176		(33)		143
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	3		14		(6)		11
Net Current Period Other Comprehensive Income (Loss)	3		190		(39)		154
Balance as of December 31, 2021	$	(6)	$	(355)	$	11	$	(350)
Other Comprehensive Income (Loss) before Reclassifications	—		(72)		(158)		(230)
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	3		1		26		30
Net Current Period Other Comprehensive Income (Loss)	3		(71)		(132)		(200)
Balance as of December 31, 2022	$	(3)	$	(426)	$	(121)	$	(550)
Other Comprehensive Income (Loss) before Reclassifications	9		76		61		146
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	(3)		248		(20)		225
Net Current Period Other Comprehensive Income (Loss)	6		324		41		371
Balance as of December 31, 2023	$	3	$	(102)	$	(80)	$	(179)




PSEG		Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Statement of Operations
		Year Ended December 31, 2021
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
		Millions
Cash Flow Hedges
Interest Rate Derivatives	Interest Expense	$	(4)	$	1	$	(3)
Total Cash Flow Hedges		(4)		1		(3)
Pension and OPEB Plans
Amortization of Prior Service (Cost) Credit	Net Non-Operating Pension and OPEB Credits (Costs)	21		(6)		15
Amortization of Actuarial Loss	Net Non-Operating Pension and OPEB Credits (Costs)	(41)		12		(29)
Total Pension and OPEB Plans		(20)		6		(14)
Available-for-Sale Securities
Realized Gains (Losses)	Net Gains (Losses) on Trust Investments	9		(3)		6
Total Available-for-Sale Securities		9		(3)		6
Total		$	(15)	$	4	$	(11)

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PSEG		Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Statement of Operations
		Year Ended December 31, 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
		Millions
Cash Flow Hedges
Interest Rate Derivatives	Interest Expense	$	(5)	$	2	$	(3)
Total Cash Flow Hedges		(5)		2		(3)
Pension and OPEB Plans
Amortization of Prior Service (Cost) Credit	Net Non-Operating Pension and OPEB Credits (Costs)	21		(6)		15
Amortization of Actuarial Loss	Net Non-Operating Pension and OPEB Credits (Costs)	(22)		6		(16)
Total Pension and OPEB Plans		(1)		—		(1)
Available-for-Sale Securities
Realized Gains (Losses)	Net Gains (Losses) on Trust Investments	(43)		17		(26)
Total Available-for-Sale Securities		(43)		17		(26)
Total		$	(49)	$	19	$	(30)




PSEG		Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Statement of Operations
		Year Ended December 31, 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
		Millions
Cash Flow Hedges

Interest Rate Derivatives	Interest Expense	$	5	$	(2)	$	3
Total Cash Flow Hedges		5		(2)		3
Pension and OPEB Plans
Amortization of Prior Service (Cost) Credit	Net Non-Operating Pension and OPEB Credits (Costs)	8		(2)		6
Amortization of Actuarial Loss	Net Non-Operating Pension and OPEB Credits (Costs)	(20)		6		(14)
Pension Settlement Charge	Net Non-Operating Pension and OPEB Credits (Costs)	(334)		94		(240)
Total Pension and OPEB Plans		(346)		98		(248)
Available-for-Sale Securities
Realized Gains (Losses)	Net Gains (Losses) on Trust Investments	34		(14)		20
Total Available-for-Sale Securities		34		(14)		20
Total		$	(307)	$	82	$	(225)

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Note 22. Earnings Per Share (EPS) and Dividends

EPS

Basic EPS is calculated by dividing Net Income (Loss) by the weighted average number of shares of common stock outstanding. Diluted EPS is calculated by dividing Net Income (Loss) by the weighted average number of shares of common stock outstanding, plus dilutive potential shares related to PSEG’s stock based compensation. For additional information on PSEG’s stock compensation plans see Note 18. Stock Based Compensation. The following table shows the effect of these dilutive potential shares on the weighted average number of shares outstanding used in calculating diluted EPS:



	Years Ended December 31,
	2023				2022				2021
	Basic		Diluted		Basic		Diluted		Basic		Diluted
EPS Numerator:
(Millions)
Net Income (Loss)	$	2,563	$	2,563	$	1,031	$	1,031	$	(648)	$	(648)
EPS Denominator:
(Millions)
Weighted Average Common Shares Outstanding	498		498		498		498		504		504
Effect of Stock Based Compensation Awards	—		2		—		3		—		—
Total Shares	498		500		498		501		504		504
EPS:
Net Income (Loss)	$	5.15	$	5.13	$	2.07	$	2.06	$	(1.29)	$	(1.29)

Approximately 3 million potentially dilutive shares were excluded from total shares used to calculate the diluted loss per share for the year ended December 31, 2021, as their impact was antidilutive.

From time to time, PSEG may repurchase shares to satisfy obligations under equity compensation awards and repurchase shares to satisfy purchases by employees under the ESPP.

For additional information on all the types of long-term incentive awards, see Note 18. Stock Based Compensation.

During 2022, PSEG completed a $500 million share repurchase program authorized by the Board of Directors in September 2021 resulting in an aggregate repurchase of approximately 7.4 million shares.

Common Stock Dividends



	Years Ended December 31,
Dividend Payments on Common Stock	2023		2022		2021
Per Share	$	2.28	$	2.16	$	2.04
in Millions	$	1,137	$	1,079	$	1,031

On February 13, 2024, PSEG’s Board of Directors approved a $0.60 per share common stock dividend for the first quarter of 2024.

Note 23. 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 have been made to the content and manner in

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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 revised its reportable segments 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 corporation) 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 periods presented in the following tables 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 selling energy, capacity and ancillary services into the markets for these products. PSEG Power also enters into bilateral contracts for energy, gas and other energy-related contracts to optimize the value of its portfolio of generating assets and its 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 corporation) and Services.



	PSE&G		PSEG Power & Other		Eliminations (A)		Consolidated Total
	Millions
Year Ended December 31, 2023
Operating Revenues	$	7,807	$	4,533	$	(1,103)	$	11,237
Depreciation and Amortization	980		155		—		1,135
Operating Income (Loss)	1,974		1,711		—		3,685
Income from Equity Method Investments	—		1		—		1
Interest Income	19		38		(4)		53
Interest Expense	493		259		(4)		748
Income (Loss) before Income Taxes	1,675		1,406		—		3,081
Income Tax Expense (Benefit)	160		358		—		518
Net Income (Loss) (B) (C)	$	1,515	$	1,048	$	—	$	2,563
Gross Additions to Long-Lived Assets	$	2,998	$	327	$	—	$	3,325
As of December 31, 2023
Total Assets	$	42,873	$	8,407	$	(539)	$	50,741
Investments in Equity Method Subsidiaries	$	—	$	17	$	—	$	17

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	PSE&G		PSEG Power & Other		Eliminations (A)		Consolidated Total
	Millions
Year Ended December 31, 2022
Operating Revenues	$	7,935	$	3,266	$	(1,401)	$	9,800
Depreciation and Amortization	935		165		—		1,100
Operating Income (Loss)	1,892		(511)		—		1,381
Income from Equity Method Investments	—		14		—		14
Interest Income	19		13		(1)		31
Interest Expense	427		202		(1)		628
Income (Loss) before Income Taxes	1,832		(830)		—		1,002
Income Tax Expense (Benefit)	267		(296)		—		(29)
Net Income (Loss) (B) (C)	$	1,565	$	(534)	$	—	$	1,031
Gross Additions to Long-Lived Assets	$	2,590	$	298	$	—	$	2,888
As of December 31, 2022
Total Assets	$	39,960	$	9,285	$	(527)	$	48,718
Investments in Equity Method Subsidiaries	$	—	$	306	$	—	$	306



	PSE&G		PSEG Power & Other		Eliminations (A)		Consolidated Total
	Millions
Year Ended December 31, 2021
Operating Revenues	$	7,122	$	3,767	$	(1,167)	$	9,722
Depreciation and Amortization	928		288		—		1,216
Operating Income (Loss)	1,818		(2,674)		—		(856)
Income from Equity Method Investments	—		16		—		16
Interest Income	14		6		—		20
Interest Expense	402		169		—		571
Income (Loss) before Income Taxes	1,770		(2,859)		—		(1,089)
Income Tax Expense (Benefit)	324		(765)		—		(441)
Net Income (Loss) (B) (C)	$	1,446	$	(2,094)	$	—	$	(648)
Gross Additions to Long-Lived Assets	$	2,447	$	272	$	—	$	2,719
As of December 31, 2021
Total Assets	$	37,198	$	12,258	$	(457)	$	48,999
Investments in Equity Method Subsidiaries	$	—	$	173	$	—	$	173

(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 24. Related-Party Transactions.

(B)Includes a $239 million after-tax pension charge due to the remeasurement of the qualified pension plans as a result of the pension settlement transaction in the third quarter of 2023. Includes after-tax impairments of $92 million related to certain Energy Holdings investments and additional adjustments related to the sale of PSEG Power’s fossil generation assets in the year ended December 31, 2022. Includes after-tax impairment losses and other charges, including debt extinguishment costs, related to the sale of the fossil generating assets at PSEG Power of $2,158 million in the year ended December 31, 2021. See Note 3. Asset Dispositions and Impairments for additional information.

(C)Includes net after-tax gain (loss) of $959 million, $(457) million and $(446) million in the years ended December 31, 2023, 2022 and 2021, respectively at PSEG Power related to the impacts of non-trading commodity mark-to-market activity, which consists of the financial impact from positions with future delivery dates.

144

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Table of Contents

Note 24. 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 presented as follows:



	Years Ended December 31,
Related Party Transactions	2023		2022		2021
	Millions
Billings from Affiliates:
Net Billings from PSEG Power (A)	$	1,065	$	1,388	$	1,144
Administrative Billings from Services (B)	443		$	445	394
Total Billings from Affiliates	$	1,508	$	1,833	$	1,538



	Years Ended December 31,
Related Party Transactions	2023		2022
	Millions

Payable to PSEG Power (A)	$	264	$	313
Payable to Services (B)	121		98
Payable to PSEG (C)	119		74
Accounts Payable—Affiliated Companies	$	504	$	485
Working Capital Advances to Services (D)	$	33	$	33
Long-Term Accrued Taxes Payable	$	2	$	9

(A)PSE&G has 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 electric 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 and for the ZEC sales are prescribed by the BPU. BGS and BGSS sales are billed and 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 pays all payroll taxes and receives reimbursement from its affiliated companies for their respective portions. In addition, 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.

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

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

PSEG and PSE&G

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 and 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 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

We have conducted assessments of our internal control over financial reporting as of December 31, 2023, as required by Section 404 of the Sarbanes-Oxley Act, using the framework promulgated by the Committee of Sponsoring Organizations of the Treadway Commission, commonly referred to as “COSO.” Managements’ reports on PSEG’s and PSE&G’s internal control over financial reporting are included on pages 147 and 148, respectively. The Independent Registered Public Accounting Firm’s report with respect to the effectiveness of PSEG’s internal control over financial reporting is included on page 149. Management has concluded that internal control over financial reporting is effective as of December 31, 2023.

We continually review our disclosure controls and procedures and make changes, as necessary, to ensure the quality of our financial reporting. There have been no changes in internal control over financial reporting that occurred during the fourth quarter of 2023 that have materially affected, or are reasonably likely to materially affect, each registrant’s internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

Director and Officer Rule 10b5-1 and non-Rule 10b5-1 Trading Plans

During the three months ended December 31, 2023, none of PSEG’s directors or officers adopted, terminated or modified a Rule 10b5-1 trading arrangement or non-Rule 10b5-1 trading arrangement (as such terms are defined in Item 408 of Regulation S-K of the Securities Act of 1933).

ITEM 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS

Not applicable.

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MANAGEMENT REPORT ON INTERNAL CONTROL OVER

FINANCIAL REPORTING—PSEG

Management of Public Service Enterprise Group Incorporated (PSEG) is responsible for establishing and maintaining effective internal control over financial reporting and for the assessment of the effectiveness of internal control over financial reporting. As defined by the SEC in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and implemented by the company’s management and other personnel, with oversight by the Audit Committee of the Board of Directors to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America (generally accepted accounting principles).

PSEG’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of PSEG’s assets; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of PSEG are being made only in accordance with authorizations of PSEG’s management and directors; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of PSEG’s assets that could have a material effect on the financial statements.

In connection with the preparation of PSEG’s annual financial statements, management of PSEG has undertaken an assessment, which includes the design and operational effectiveness of PSEG’s internal control over financial reporting based on criteria established in the Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, commonly referred to as “COSO”. The COSO framework is based upon five integrated components of control: control environment, risk assessment, control activities, information and communications and ongoing monitoring.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projection of any evaluation of effectiveness to future periods is subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Based on the assessment performed, management has concluded that PSEG’s internal control over financial reporting is effective and provides reasonable assurance regarding the reliability of PSEG’s financial reporting and the preparation of its financial statements as of December 31, 2023 in accordance with generally accepted accounting principles. Further, management has not identified any material weaknesses in internal control over financial reporting as of December 31, 2023.

PSEG’s external auditors, Deloitte & Touche LLP, have audited PSEG’s financial statements for the year ended December 31, 2023 included in this annual report on Form 10-K and, as part of that audit, have issued a report on the effectiveness of PSEG’s internal control over financial reporting, a copy of which is included in this annual report on Form 10-K.



/s/ RALPH A. LAROSSA
Chief Executive Officer

/s/ DANIEL J. CREGG
Chief Financial Officer
February 26, 2024

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MANAGEMENT REPORT ON INTERNAL CONTROL OVER

FINANCIAL REPORTING—PSE&G

Management of Public Service Electric and Gas Company (PSE&G) is responsible for establishing and maintaining effective internal control over financial reporting and for the assessment of the effectiveness of internal control over financial reporting. As defined by the SEC in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and implemented by the company’s management and other personnel, with oversight by the Audit Committee of the Board of Directors of its parent, Public Service Enterprise Group Incorporated, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America (generally accepted accounting principles).

PSE&G’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of PSE&G’s assets; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of PSE&G are being made only in accordance with authorizations of PSE&G’s management and directors; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of PSE&G’s assets that could have a material effect on the financial statements.

In connection with the preparation of PSE&G’s annual financial statements, management of PSE&G has undertaken an assessment, which includes the design and operational effectiveness of PSE&G’s internal control over financial reporting based on criteria established in the Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, commonly referred to as “COSO”. The COSO framework is based upon five integrated components of control: control environment, risk assessment, control activities, information and communications and ongoing monitoring.

Based on the assessment performed, management has concluded that PSE&G’s internal control over financial reporting is effective and provides reasonable assurance regarding the reliability of PSE&G’s financial reporting and the preparation of its financial statements as of December 31, 2023 in accordance with generally accepted accounting principles. Further, management has not identified any material weaknesses in internal control over financial reporting as of December 31, 2023.



/s/ RALPH A. LAROSSA
Chief Executive Officer

/s/ DANIEL J. CREGG
Chief Financial Officer
February 26, 2024

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of

Public Service Enterprise Group Incorporated

Opinion on Internal Control over Financial Reporting

We have audited the internal control over financial reporting of Public Service Enterprise Group Incorporated and subsidiaries (the “Company” or PSEG) as of December 31, 2023, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2023, based on criteria established in Internal Control — Integrated Framework (2013) issued by COSO.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated financial statements and the consolidated financial statement schedule listed in the Index at Item 15(B)(a) as of and for the year ended December 31, 2023, of the Company and our report dated February 26, 2024, expressed an unqualified opinion on those financial statements.

Basis for Opinion

The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management Report on Internal Control Over Financial Reporting - PSEG. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ DELOITTE & TOUCHE LLP

Morristown, New Jersey

February 26, 2024

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PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE

GOVERNANCE

Executive Officers

PSEG

The information required by Item 10 of Form 10-K with respect to executive officers is set forth in Part I. Information About Our Executive Officers (PSEG).

PSE&G

Omitted pursuant to conditions set forth in General Instruction I of Form 10-K.

Directors

PSEG

The information required by Item 10 of Form 10-K with respect to (i) present directors of PSEG who are nominees for election as directors at PSEG’s 2024 Annual Meeting of Stockholders, (ii) the director nomination process, and (iii) the composition of the Audit Committee of the Board, is set forth under the headings “Nominees For Director-Biographical Information,” “Overview of Board Nominees-Board Refreshment and Tenure,” and “-Board Membership Selection,” and “Corporate Governance-Board Committees,” respectively, in PSEG’s definitive Proxy Statement for such Annual Meeting of Stockholders, which definitive Proxy Statement is expected to be filed with the U.S. Securities and Exchange Commission (SEC) on or about March 7, 2024 and which information set forth under said heading is incorporated herein by this reference thereto.

PSE&G

Omitted pursuant to conditions set forth in General Instruction I of Form 10-K.

Standards of Conduct

Our Standards of Conduct (Standards) is a code of ethics applicable to us and our subsidiaries. The Standards are an integral part of our business conduct compliance program and embody our commitment to conduct operations in accordance with the highest legal and ethical standards. The Standards apply to all of our directors and employees (including PSE&G’s, PSEG Power’s, Energy Holdings’ and Services’ respective principal executive officer, principal financial officer, principal accounting officer or Controller and persons performing similar functions). Each such person is responsible for understanding and complying with the Standards. The Standards are posted on our website, https://corporate.pseg.com/aboutpseg/leadershipandgovernance/standardsofconduct You can get a free copy of the Standards by making an oral or written request directed to:

Vice President, Investor Relations

PSEG Services Corporation

80 Park Plaza, 4th Floor

Newark, NJ 07102

Telephone (973) 430-6565

The Standards establish a set of common expectations for behavior to which each employee must adhere in dealings with investors, customers, fellow employees, competitors, vendors, government officials, the media and all others who may associate their words and actions with us. The Standards have been developed to provide reasonable assurance that, in conducting our business, employees behave ethically and in accordance with the law and do not take advantage of investors, regulators or customers through manipulation, abuse of confidential information or misrepresentation of material facts.

We will post on our website, https://corporate.pseg.com/aboutpseg/leadershipandgovernance/standardsofconduct:

•Any amendment (other than one that is technical, administrative or non-substantive) that we adopt to our Standards; and

•Any grant by us of a waiver from the Standards that applies to any director or executive officer and that relates to any element enumerated by the SEC.

In 2023, we did not grant any waivers to the Standards.

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ITEM 11. EXECUTIVE COMPENSATION

PSEG

The information required by Item 11 of Form 10-K is set forth in PSEG’s definitive Proxy Statement for the 2024 Annual Meeting of Stockholders which definitive Proxy Statement is expected to be filed with the SEC on or about March 7, 2024 and such information that is responsive to this Item 11, except for information set forth under the heading “Pay Versus Performance,” is incorporated herein by this reference thereto.

PSE&G

Omitted pursuant to conditions set forth in General Instruction I of Form 10-K.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS

AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

PSEG

The information required by Item 12 of Form 10-K with respect to directors, executive officers and certain beneficial owners is set forth under the heading “Security Ownership of Directors, Management and Certain Beneficial Owners” in PSEG’s definitive Proxy Statement for the 2024 Annual Meeting of Stockholders which definitive Proxy Statement is expected to be filed with the SEC on or about March 7, 2024 and such information set forth under such heading is incorporated herein by this reference thereto.

For information relating to securities authorized for issuance under equity compensation plans, see Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.

PSE&G

Omitted pursuant to conditions set forth in General Instruction I of Form 10-K.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND

DIRECTOR INDEPENDENCE

PSEG

The information required by Item 13 of Form 10-K is set forth under the heading “Corporate Governance-Certain Relationships and Related Person Transactions” in PSEG’s definitive Proxy Statement for the 2024 Annual Meeting of Stockholders which definitive Proxy Statement is expected to be filed with the SEC on or about March 7, 2024 and such information set forth under such heading is incorporated herein by this reference thereto.

PSE&G

Omitted pursuant to conditions set forth in General Instruction I of Form 10-K.

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

The information required by Item 14 of Form 10-K is set forth under the heading “Oversight of the Independent Auditor-Fees Billed by Deloitte for 2023 and 2022” in PSEG’s definitive Proxy Statement for the 2024 Annual Meeting of Stockholders which definitive Proxy Statement is expected to be filed with the SEC on or about March 7, 2024. Such information set forth under such heading is incorporated herein by this reference hereto.

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PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES

(A) The following Financial Statements are filed as a part of this report:

a.Public Service Enterprise Group Incorporated’s Consolidated Balance Sheets as of December 31, 2023 and 2022 and the related Consolidated Statements of Operations, Comprehensive Income, Cash Flows and Stockholders’ Equity for the three years ended December 31, 2023 on pages 60 through 65.

b.Public Service Electric and Gas Company’s Consolidated Balance Sheets as of December 31, 2023 and 2022 and the related Consolidated Statements of Operations, Comprehensive Income, Cash Flows and Common Stockholder’s Equity for the three years ended December 31, 2023 on pages 66 through 71.

(B) The following documents are filed as a part of this report:

a.PSEG’s Financial Statement Schedules:

Schedule II—Valuation and Qualifying Accounts for each of the three years in the period ended December 31, 2023 (page 157).

b.PSE&G’s Financial Statement Schedules:

Schedule II—Valuation and Qualifying Accounts for each of the three years in the period ended December 31, 2023 (page 157).

Schedules other than those listed above are omitted for the reason that they are not required or are not applicable, or the required information is shown in the consolidated financial statements or notes thereto.


	LIST OF EXHIBITS:
a.		PSEG:
3a		Certificate of Incorporation Public Service Enterprise Group Incorporated(1)
3b		Certificate of Amendment of Certificate of Incorporation of Public Service Enterprise Group Incorporated, effective April 23, 1987(2)
3c		Certificate of Amendment of Certificate of Incorporation of Public Service Enterprise Group Incorporated, effective April 20, 2007(3)
3d		By-Laws of Public Service Enterprise Group Incorporated effective February 14, 2023(4)
4a		Indenture between Public Service Enterprise Group Incorporated and First Union National Bank (U.S. Bank National Association, successor), as Trustee, dated January 1, 1998 providing for Deferrable Interest Subordinated Debentures in Series (relating to Quarterly Preferred Securities)(5)
4b		Indenture between Public Service Enterprise Group Incorporated and U.S. Bank National Association (as successor to First Union National Bank), as Trustee, dated November 1, 1998 providing for Senior Debt Securities(6)
4c		Description of Common Stock(7)
10a(1)		Supplemental Executive Retirement Income Plan, amended effective July 1, 2019(8)
10a(2)		Retirement Income Reinstatement Plan for Non-Represented Employees, Amended effective July 1, 2019(9)
10a(3)		2007 Equity Compensation Plan for Outside Directors, amended and restated effective November 19, 2019 (10)
10a(4)		Deferred Compensation Plan for Directors, amended effective January 1, 2019(11)
10a(5 )		Key Executive Severance Plan of Public Service Enterprise Group Incorporated, amended effective July 18, 2022 (1 2 )
10a(6 )		Stock Plan for Outside Directors, as amended(13)
10a(7 )		Compensation Plan for Outside Directors(14)
10a(8 )		2004 Long-Term Incentive Plan, amended and restated as of April 16, 2013(15)

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	LIST OF EXHIBITS:
10a(9)		Form of Agreement for Advancement of Expenses with Outside Directors(16)
10a(1 0 )		Agreement with Tamara L. Linde dated June 18, 2014(17)
10a(1 1 )		Agreement with Daniel J. Cregg dated September 22, 2015(18)
10a(1 2 )		Clawback Practice, effective February 20, 2018(19)
10a(1 3 )		Agreement with Ralph A. LaRossa dated April 18, 2022(2 0 )
10a(1 4 )		2021 Long-Term Incentive Plan, effective April 20, 2021(21)
10a(1 5 )		2021 Equity Compensation Plan for Outside Directors, effective April 20, 2021(2 2 )
10a(16 )		Agreement with Kim C. Hanemann dated May 21, 2021(2 3 )
10a(17)		Retention Award for Daniel J. Cregg dated April 17, 2023(24 )
10a(18)		2021 Equity Compensation Plan for Outside Directors - Restricted Stock Unit Award Agreemen t(25)
10a(19)		Deferred Compensation Plan for Certain Employees, amended and restated effective November 20, 2023
10a(20)		Management Incentive Compensation Plan, amended and effective January 1, 2024
10a(21)		Equity Deferral Plan, amended and restated effective November 20, 2023
10a(22)		2021 Long-Term Incentive Plan - Performance Share Units Award Agreement
10a(23)		2021 Long-Term Incentive Plan - Restricted Stock Unit Award Agreement
10a(24)		Agreement with Charles V. McFeaters dated April 18, 2023
21		Subsidiaries of the Registrant
23		Consent of Independent Registered Public Accounting Firm
31		Certification by Ralph A. LaRossa, pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934 (1934 Act)
31a		Certification by Daniel J. Cregg, pursuant to Rules 13a-14 and 15d-14 of the 1934 Act
32		Certification by Ralph A. LaRossa, pursuant to Section 1350 of Chapter 63 of Title 18 of the U.S. Code
32a		Certification by Daniel J. Cregg, pursuant to Section 1350 of Chapter 63 of Title 18 of the U.S. Code
97		Clawback Practice for Recovery of Erroneously Awarded Compensation to Executive Officers
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.
101.SCH		Inline XBRL Taxonomy Extension Schema
101.CAL		Inline XBRL Taxonomy Calculation Linkbase
101.LAB		Inline XBRL Taxonomy Extension Labels Linkbase
101.PRE		Inline XBRL Taxonomy Extension Presentation Linkbase
101.DEF		Inline XBRL Taxonomy Extension Definition Document
104		Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)
b.		PSE&G
3a(1)		Restated Certificate of Incorporation of PSE&G(26)
3a(2)		Certificate of Amendment of Certificate of Restated Certificate of Incorporation of PSE&G filed February 18, 1987 with the State of New Jersey adopting limitations of liability provisions in accordance with an amendment to New Jersey Business Corporation Act(27)
3a(3)		Certificate of Amendment of Restated Certificate of Incorporation of PSE&G filed June 17, 1992 with the State of New Jersey, establishing the 7.44% Cumulative Preferred Stock ($100 Par) as a series of Preferred Stock(28)
3a(4)		Certificate of Amendment of Restated Certificate of Incorporation of PSE&G filed March 11, 1993 with the State of New Jersey, establishing the 5.97% Cumulative Preferred Stock ($100 Par) as a series of Preferred Stock(29)
3a(5)		Certificate of Amendment of Restated Certificate of Incorporation of PSE&G filed January 27, 1994 with the State of New Jersey, establishing the 6.92% Cumulative Preferred Stock ($100 Par) and the 6.75% Cumulative Preferred Stock ($25 Par) as a series of Preferred Stock(30)
3b(1)		By-Laws of PSE&G as in effect April 17, 2007(31)
4a(1)		Indenture between PSE&G and Fidelity Union Trust Company (now, Wachovia Bank, National Association), as Trustee, dated August 1, 1924(32), securing First and Refunding Mortgage Bond and Supplemental Indentures between PSE&G and U.S. Bank National Association, successor, as Trustee, supplemental to Exhibit 4a(1), dated as follows:

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	LIST OF EXHIBITS:
4a(2)		June 1, 1937(33)
4a(3)		July 1, 1937(34)
4a(4)		June 1, 1991 (No. 1)(35)
4a(5)		August 1, 2004 (No. 4)(36)
4a(6)		April 1, 2007(37)
4a(7)		November 1, 2009(38)
4a(8)		May 1, 2012(39)
4a(9)		May 1, 2013(40)
4a(10)		August 1, 2014(41)
4a(11)		May 1, 2015(42)
4a(12)		September 1, 2016(43)
4a(13)		April 1, 2018(44)
4a(14)		December 1, 2019(4 5 )
4a(15)		March 1, 2022(4 6 )
4b		Description of the First and Refunding Mortgage Bonds(4 7 )
4c		Indenture of Trust between PSE&G and Chase Manhattan Bank (National Association) (The Bank of New York Mellon, successor), as Trustee, providing for Secured Medium-Term Notes dated July 1, 1993(48)
4d		Indenture dated as of December 1, 2000 between Public Service Electric and Gas Company and First Union National Bank (U.S. Bank National Association, successor), as Trustee, providing for Senior Debt Securities(49)
10a(1)		Supplemental Executive Retirement Income Plan, amended effective July 1, 2019(8)
10a(2)		Retirement Income Reinstatement Plan for Non-Represented Employees, Amended effective July 1, 2019(9)
10a(3)		2007 Equity Compensation Plan for Outside Directors, amended and restated effective November 19, 2019(10)
10a(4)		Deferred Compensation Plan for Directors, amended effective January 1, 2019(11)
10a(5 )		Key Executive Severance Plan of Public Service Enterprise Group Incorporated, amended effective July 18, 2022(1 2 )
10a(6 )		Stock Plan for Outside Directors, as amended(13)
10a(7 )		Compensation Plan for Outside Directors(14)
10a(8)		2004 Long-Term Incentive Plan amended and restated as of April 16, 2013(15)
10a(9)		Form of Agreement for Advancement of Expenses with Outside Directors(50)
10a(1 0 )		Agreement with Tamara L. Linde dated June 18, 2014(17)
10a(1 1 )		Agreement with Daniel J. Cregg dated September 22, 2015(18)
10a(1 2 )		Clawback Practice, effective February 20, 2018(19)
10a(1 3 )		Agreement with Ralph A. LaRossa dated April 18, 2022(20)
10a(1 4 )		2021 Long-Term Incentive Plan, effective April 20, 2021(21)
10a(1 5 )		2021 Equity Compensation Plan for Outside Directors, effective April 20, 2021(2 2 )
10a(1 6 )		Agreement with Kim C. Hanemann dated May 21, 2021(2 3 )
10a(17)		Retention Award for Daniel J. Cregg dated April 17, 2023(24)
10a(18)		2021 Equity Compensation Plan for Outside Directors - Restricted Stock Unit Award Agreement (2 5)
10a(19)		Deferred Compensation Plan for Certain Employees, amended and restated effective November 30, 2023
10a(20)		Management Incentive Compensation Plan, amended and effective January 1, 2024
10a(21)		Equity Deferral Plan, amended and restated effective November 20, 2023
10a(22)		2021 Long-Term Incentive Plan - Performance Share Units Award Agreement
10a(23)		2021 Long-Term Incentive Plan - Restricted Stock Unit Award Agreement
23a		Consent of Independent Registered Public Accounting Firm

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	LIST OF EXHIBITS:
31b		Certification by Ralph A. LaRossa, pursuant to Rules 13a-14 and 15d-14 of the 1934 Act
31c		Certification by Daniel J. Cregg, pursuant to Rules 13a-14 and 15d-14 of the 1934 Act
32b		Certification by Ralph A. LaRossa, pursuant to Section 1350 of Chapter 63 of Title 18 of the U.S. Code
32c		Certification by Daniel J. Cregg, pursuant to Section 1350 of Chapter 63 of Title 18 of the U.S. Code
97		Clawback Practice for Recovery of Erroneously Awarded Compensation to Executive Officers
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
101.SCH		Inline XBRL Taxonomy Extension Schema
101.CAL		Inline XBRL Taxonomy Calculation Linkbase
101.LAB		Inline XBRL Taxonomy Extension Labels Linkbase
101.PRE		Inline XBRL Taxonomy Extension Presentation Linkbase
101.DEF		Inline XBRL Taxonomy Extension Definition Document
104		Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)

(1)Filed as Exhibit 3.1a with Quarterly Report on Form 10-Q for the quarter ended March 31, 2007, File No. 001-09120, on May 4, 2007 and incorporated herein by this reference.

(2)Filed as Exhibit 3.1b with Quarterly Report on Form 10-Q for the quarter ended March 31, 2007, File No. 001-09120, on May 4, 2007 and incorporated herein by this reference.

(3)Filed as Exhibit 3.1c with Quarterly Report on Form 10-Q for the quarter ended March 31, 2007, File No. 001-09120, on May 4, 2007 and incorporated herein by this reference.

(4)Filed as Exhibit 3.1 with Current Report on Form 8-K, File No. 001-09120, on February 17, 2023 and incorporated herein by this reference.

(5)Filed as Exhibit 4(f) with Quarterly Report on Form 10-Q for the quarter ended March 31, 1998, File No. 001-09120, on May 13, 1998 and incorporated herein by this reference.

(6)Filed as Exhibit 4(f) with Annual Report on Form 10-K for the year ended December 31, 1998, File No. 001-09120, on February 23, 1999 and incorporated herein by this reference

(7)Filed as Exhibit 4c for PSEG with Annual Report on Form 10-K for the year ended December 31, 2019. File No. 001-09120, on February 26, 2020 and incorporated herein by this reference.

(8)Filed as Exhibit 10.1 with Quarterly Report on Form 10-Q for the quarter ended September 30, 2019, File No. 001-09120, on October 31, 2019 and incorporated herein by this reference.

(9)Filed as Exhibit 10.2 with Quarterly Report on Form 10-Q for the quarter ended September 30, 2019, File No. 001-09120, on October 31, 2019 and incorporated herein by this reference.

(10)Filed as Exhibit 10a(3) with Annual Report on Form 10-K for the year ended December 31, 2020, File No. 001-09120, on March 1, 2021 and incorporated herein by this reference.

(11)Filed as Exhibit 10a(4) with Annual Report on Form 10-K for the year ended December 31, 2018, File No. 001-09120 on February 27, 2019 and incorporated herein by this reference.

(12)Filed as Exhibit 10.1 with Current Report on Form 8-K, File No. 001-09120, on July 22, 2022 and incorporated herein by this reference.

(13)Filed as Exhibit 10a(17) with Annual Report on Form 10-K for the year ended December 31, 2002, File No. 001-09120, on February 26, 2003 and incorporated herein by this reference.

(14)Filed as Exhibit 10a(20) with Annual Report on Form 10-K for the year ended December 31, 2002, File No. 001-09120, on February 26, 2003 and incorporated herein by this reference.

(15)Filed as Exhibit 10 with Quarterly Report on Form 10-Q for the quarter ended March 31, 2013, File No. 001-09120, on May 1, 2013 and incorporated herein by this reference.

(16)Filed as Exhibit 10.1 with Current Report on Form 8-K, File No. 001-09120, on February 19, 2009 and incorporated herein by this reference.

(17)Filed as Exhibit 10a with Annual Report on Form 10-K for the year ended December 31, 2014, File No. 001-09120, on February 26, 2015, and incorporated herein by this reference.

(18)Filed as Exhibit 10 with Quarterly Report on Form 10-Q for the quarter ended September 30, 2015, File No. 001-09120, on October 30, 2015, and incorporated herein by this reference.

(19)Filed as Exhibit 10a(20) with Annual Report on Form 10-K for the year ended December 31, 2017, File No. 001-09120 on February 26, 2018 and incorporated herein by this reference.

(20)Filed as Exhibit 10.2 with Current Report on Form 8-K, File No. 001-09120, on April 19, 2022 and incorporated herein by this reference.

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(21)Filed as Exhibit 99.1 with Current Report on Form 8-K, File No. 001-09120, on April 22, 2021 and incorporated herein by this reference.

(22)Filed as Exhibit 4.6 to Registration Statement on Form S-8, File No. 001-09120, on April 23, 2021 and incorporated herein by this reference.

(23)Filed as Exhibit 10(4) with Quarterly Report on Form 10-Q for the quarter ended June 30, 2021, File No. 001-09120, on August 9, 2021 and incorporated herein by this reference.

(24)Filed as Exhibit 10.1 with Quarterly Report on Form 10-Q for the quarter ended March 31, 2023, File No. 001-09120, and incorporated herein by reference.

(25)Filed as Exhibit 10.3 with Quarterly Report on Form 10-Q for the quarter ended June 30, 2023, File No. 001-09120, and incorporated herein by reference.

(26)Filed as Exhibit 3a(1) on Form 8-A, File No. 001-00973, on February 4, 1994 and incorporated herein by this reference.

(27)Filed as Exhibit 3a(2) on Form 8-A, File No. 001-00973, on February 4, 1994 and incorporated herein by this reference.

(28)Filed as Exhibit 3a(3) on Form 8-A, File No. 001-00973, on February 4, 1994 and incorporated herein by this reference.

(29)Filed as Exhibit 3a(4) on Form 8-A, File No. 001-00973, on February 4, 1994 and incorporated herein by this reference.

(30)Filed as Exhibit 3a(5) on Form 8-A, File No. 001-00973, on February 4, 1994 and incorporated herein by this reference.

(31)Filed as Exhibit 3.3 with Quarterly Report on Form 10-Q for the quarter ended March 31, 2007, File No. 001-00973, on May 4, 2007 and incorporated herein by this reference.

(32)Filed as Exhibit 4b(1) with Annual Report on Form 10-K for the year ended December 31, 1980, File No. 001-00973, on February 18, 1981 and incorporated herein by this reference.

(33)Filed as Exhibit 4b(3) with Annual Report on Form 10-K for the year ended December 31, 1980, File No. 001-00973, on February 18, 1981 and incorporated herein by this reference.

(34)Filed as Exhibit 4b(4) with Annual Report on Form 10-K for the year ended December 31, 1980, File No. 001-00973, on February 18, 1981 and incorporated herein by this reference.

(35)Filed as Exhibit 4(i) on Form 8-A, File No. 001-00973, on June 1, 1991 and incorporated herein by this reference.

(36)Filed as Exhibit 4a(28) with Annual Report on Form 10-K for the year ended December 31, 2004, File No. 001-00973, on March 1, 2005 and incorporated herein by this reference.

(37)Filed as Exhibit 4a(28) with Annual Report on Form 10-K for the year ended December 31, 2007, File No. 001-00973, on February 28, 2008 and incorporated herein by this reference.

(38)Filed as Exhibit 4a(30) with Annual Report on Form 10-K for the year ended December 31, 2009, File No. 001-00973, on February 25, 2010 and incorporated herein by this reference.

(39)Filed as Exhibit 4a(32) with Annual Report on Form 10-K for the year ended December 31, 2012, File No. 001-00973, on February 26, 2013, and incorporated herein by this reference.

(40)Filed as Exhibit 4 with Quarterly Report on Form 10-Q for the quarter ended June 30, 2013, File No. 001-00973, on July 30, 2013, and incorporated herein by this reference.

(41)Filed as Exhibit 4a(22) with Quarterly Report on Form 10-Q for the quarter ended September 30, 2014, File No. 001-09120, on October 30, 2014 and incorporated herein by this reference.

(42)Filed as Exhibit 4a(23) with Quarterly Report on Form 10-Q for the quarter ended June 30, 2015, File No. 001-09120, on July 31, 2015 and incorporated herein by this reference.

(43)Filed as Exhibit 4a(14) with Annual Report on Form 10-K for the year ended December 31, 2016, File No. 001-00973, on February 27, 2017 and incorporated herein by this reference.

(44)Filed as Exhibit 4a(15) with Quarterly Report on Form 10-Q for the quarter ended March 31, 2018, File No. 001-00973, on April 30, 2018 and incorporated herein by this reference.

(45)Filed as Exhibit 4a(15) with Annual Report on Form 10-K for the year ended December 31, 2019, File No. 001-09120, on February 26, 2020 and incorporated herein by this reference.

(46)Filed as Exhibit 4a(15) with Quarterly Report on Form 10-Q for the quarter ended March 31, 2022, File No. 001-09120, on May 3, 2022 and incorporated herein by reference.

(47)Filed as Exhibit 4b with Annual Report on Form 10-K for the year ended December 31, 2019, File No. 001-09120, on February 26, 2020 and incorporated herein by the reference.

(48)Filed as Exhibit 4 with Current Report on Form 8-K, File No. 001-00973, on December 1, 1993 and incorporated herein by this reference.

(49)Filed as Exhibit 4-6 to Registration Statement on Form S-3, File No. 333-76020, filed on December 27, 2001 and incorporated herein by this reference.

(50)Filed as Exhibit 10.2 with Current Report on Form 8-K, File No. 001-00973, on February 19, 2009 and incorporated herein by this reference.

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Schedule II—Valuation and Qualifying Accounts Years Ended December 31, 2023—December 31, 2021

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED



Column A	Column B		Column C Additions					Column D			Column E
Description	Balance at Beginning of Period		Charged to cost and expenses			Charged to other accounts- describe		Deductions- describe			Balance at End of Period
	Millions
2023
Allowance for Credit Losses	$	339	$	100	(A)	$	—	$	156	(B)	$	283
Materials and Supplies Valuation Reserve	10		4			—		—			14
2022
Allowance for Credit Losses	$	337	$	114	(A)	$	—	$	112	(B)	$	339
Materials and Supplies Valuation Reserve	12		1			—		3		(C)	10
2021
Allowance for Credit Losses	$	206	$	195	(A)	$	—	$	64	(B)	$	337
Materials and Supplies Valuation Reserve	10		3			—		1		(C)	12

(A)For a discussion of bad debt recoveries, see Item 8. Note 1. Organization, Basis of Presentation and Summary of Significant Accounting Policies.

(B)Accounts Receivable written off.

(C)Reserve reduced to appropriate level as a result of asset dispositions and to remove obsolete inventory.

PUBLIC SERVICE ELECTRIC AND GAS COMPANY



Column A	Column B		Column C Additions					Column D			Column E
Description	Balance at Beginning of Period		Charged to cost and expenses			Charged to other accounts- describe		Deductions- describe			Balance at End of Period
	Millions
2023
Allowance for Credit Losses	$	339	$	100	(A)	$	—	$	156	(B)	$	283
Materials and Supplies Valuation Reserve	4		3			—		—			7
2022
Allowance for Credit Losses	$	337	$	114	(A)	$	—	$	112	(B)	$	339
Materials and Supplies Valuation Reserve	3		1			—		—			4
2021
Allowance for Credit Losses	$	206	$	195	(A)	$	—	$	64	(B)	$	337
Materials and Supplies Valuation Reserve	2		2			—		1		(C)	3

(A)For a discussion of bad debt recoveries, see Item 8. Note 1. Organization, Basis of Presentation and Summary of Significant Accounting Policies.

(B)Accounts Receivable written off.

(C)Reserve reduced to appropriate level and to remove obsolete inventory.

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SIGNATURES

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

						By:			/s/ RALPH A. LAROSSA
									Ralph A. LaRossa
									Chair of the Board, President and
									Chief Executive Officer

Date: February 26, 2024

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signatures of the undersigned shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.

Signature

Title

Date

/s/ RALPH A. LAROSSA

Chair of the Board, President, Chief Executive Officer and

February 26, 2024

Ralph A. LaRossa

Director (Principal Executive Officer)

/s/ DANIEL J. CREGG

Executive Vice President and Chief Financial Officer

February 26, 2024

Daniel J. Cregg

(Principal Financial Officer)

/s/ ROSE M. CHERNICK

Vice President and Controller

February 26, 2024

Rose M. Chernick

(Principal Accounting Officer)

/s/ WILLIE A. DEESE

Director

February 26, 2024

Willie A. Deese

/s/ JAMIE M. GENTOSO

Director

February 26, 2024

Jamie M. Gentoso

/s/ BARRY H. OSTROWSKY

Director

February 26, 2024

Barry H. Ostrowsky

/s/ RICARDO G. PÉREZ

Director

February 26, 2024

Ricardo G. Pérez

/s/ VALERIE A. SMITH

Director

February 26, 2024

Valerie A. Smith

/s/ SCOTT G. STEPHENSON

Director

February 26, 2024

Scott G. Stephenson

/s/ LAURA A. SUGG

Director

February 26, 2024

Laura A. Sugg

/s/ JOHN P. SURMA

Director

February 26, 2024

John P. Surma

/s/ KENNETH Y. TANJI

Director

February 26, 2024

Kenneth Y. Tanji

/s/ SUSAN TOMASKY

Director

February 26, 2024

Susan Tomasky

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SIGNATURES



									PUBLIC SERVICE ELECTRIC AND GAS COMPANY

						By:			/s/ KIM C. HANEMANN
									Kim C. Hanemann
									President

Date: February 26, 2024

Signature

Title

Date

/s/ RALPH A. LAROSSA

Chair of the Board and Chief Executive Officer and

February 26, 2024

Ralph A. LaRossa

Director (Principal Executive Officer)

/s/ DANIEL J. CREGG

Executive Vice President and Chief Financial Officer

February 26, 2024

Daniel J. Cregg

(Principal Financial Officer)

/s/ ROSE M. CHERNICK

Vice President and Controller

February 26, 2024

Rose M. Chernick

(Principal Accounting Officer)

/s/ WILLIE A. DEESE

Director

February 26, 2024

Willie A. Deese

/s/ BARRY H. OSTROWSKY

Director

February 26, 2024

Barry H. Ostrowsky

/s/ SUSAN TOMASKY

Director

February 26, 2024

Susan Tomasky

159