PUBLIC SERVICE ENTERPRISE GROUP INC - Annual Report: 2021 (Form 10-K)

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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, 2021

☐ 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 reporting company

☐

Emerging growth company

☐

Public Service Electric and Gas Company

Large Accelerated Filer

☐

Accelerated Filer

☐

Non-accelerated Filer

☒

Smaller reporting company

☐

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						☐

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, 2021 was $29,934,856,297 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 18, 2022 was 502,077,935.

As of February 18, 2022, 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 2022 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 10, 2022, as specified herein.

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		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	9
	Human Capital Management	10
	Regulatory Issues	12
	Environmental Matters	18
	Information About Our Executive Officers (PSEG)	21
Item 1A.	Risk Factors	22
Item 1B.	Unresolved Staff Comments	35
Item 2.	Properties	35
Item 3.	Legal Proceedings	36
Item 4.	Mine Safety Disclosures	36
PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	37
Item 6.	[Reserved]	38
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	39
	Executive Overview of 2021 and Future Outlook	39
	Results of Operations	48
	Liquidity and Capital Resources	53
	Capital Requirements	57
	Critical Accounting Estimates	59
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	63
Item 8.	Financial Statements and Supplementary Data	64
	Report of Independent Registered Public Accounting Firm (PCAOB ID No. 34)	65
	Consolidated Financial Statements	70
	Notes to Consolidated Financial Statements
	Note 1. Organization, Basis of Presentation and Summary of Significant Accounting Policies	82
	Note 2. Recent Accounting Standards	88
	Note 3. Revenues	89
	Note 4. Early Plant Retirements/Asset Dispositions and Impairments	94
	Note 5. Variable Interest Entities (VIEs)	96
	Note 6. Property, Plant and Equipment and Jointly-Owned Facilities	97
	Note 7. Regulatory Assets and Liabilities	98
	Note 8. Leases	104
	Note 9. Long-Term Investments	107
	Note 10. Financing Receivables	108
	Note 11. Trust Investments	109
	Note 12. Intangibles	115
	Note 13. Asset Retirement Obligations (AROs)	116
	Note 14. Pension, Other Postretirement Benefits (OPEB) and Savings Plans	117

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	TABLE OF CONTENTS (continued)
	Note 15. Commitments and Contingent Liabilities	126
	Note 16. Debt and Credit Facilities	133
	Note 17. Schedule of Consolidated Capital Stock	138
	Note 18. Financial Risk Management Activities	138
	Note 19. Fair Value Measurements	143
	Note 20. Stock Based Compensation	146
	Note 21. Other Income (Deductions)	150
	Note 22. Income Taxes	151
	Note 23. Accumulated Other Comprehensive Income (Loss), Net of Tax	157
	Note 24. Earnings Per Share (EPS) and Dividends	159
	Note 25. Financial Information by Business Segment	160
	Note 26. Related-Party Transactions	163
Item 9.	Changes In and Disagreements With Accountants on Accounting and Financial Disclosure	164
Item 9A.	Controls and Procedures	164
Item 9B.	Other Information	164
Item 9C.	Disclosure Regarding Foreign Jurisdictions that Prevent Inspections	164
PART III
Item 10.	Directors, Executive Officers and Corporate Governance	168
Item 11.	Executive Compensation	169
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	169
Item 13.	Certain Relationships and Related Transactions, and Director Independence	169
Item 14.	Principal Accountant Fees and Services	169
PART IV
Item 15.	Exhibits, Financial Statement Schedules	170
	Schedule II - Valuation and Qualifying Accounts	175
	Signatures	176

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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 15. 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 solar and wind 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, severe weather events, acts of war, terrorism, sabotage, cyberattack or other incidents, including pandemics such as the ongoing coronavirus pandemic, 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;

•the impact of the ongoing coronavirus pandemic;

•failure to attract and retain a qualified workforce;

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

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

•adverse performance of our nuclear decommissioning and defined benefit plan trust fund investments and changes in funding requirements;

•the failure to complete, or delays in completing, the Ocean Wind offshore wind project and the failure to realize the anticipated strategic and financial benefits of this project;

•fluctuations in wholesale power and natural gas markets, including the potential impacts on the economic viability of our generation units;

•our ability to obtain adequate fuel supply;

•market risks impacting the operation of our generating stations;

•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 generation output and purchase of fuel;

•any inability of PSEG Power to meet its commitments under forward sale obligations;

•reliance on transmission facilities to maintain adequate transmission capacity for our power generation fleet;

•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 programs may not be fully approved by regulators and its capital investment may be lower than planned;

•the absence of a long-term legislative or other solution for our New Jersey nuclear plants that sufficiently values them for their carbon-free, fuel diversity and resilience attributes, or the impact of the current or subsequent payments for such attributes being materially adversely modified through legal proceedings;

•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 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

•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.

In August 2021, PSEG entered into two agreements to sell PSEG Power’s 6,750 MW fossil generating portfolio to newly formed subsidiaries of ArcLight Energy Partners Fund VII, L.P., a fund controlled by ArcLight Capital Partners, LLC. In February 2022, PSEG completed the sale of this fossil generating portfolio. As a result, risks highlighted in these forward-looking statements that relate solely to this 6,750 MW fossil generating portfolio, except for those related to certain assets and liabilities excluded from the sale transactions, primarily for obligations under environmental regulations, including possible remediation obligations under the New Jersey Industrial Site Recovery Act and the Connecticut Transfer Act, are no longer relevant to our business.

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.

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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 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 an energy company with a diversified business mix. Our operations are located primarily in the Northeastern and Mid- Atlantic United States. 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 segments.

•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 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 the generation and marketing of power and natural gas to hedge business risks and optimize the value of its portfolio of power plants, other contractual arrangements and oil and gas storage facilities. PSEG Power is no longer an SEC registrant; however, it continues to be consolidated and reported in PSEG’s financial statements as a wholly owned subsidiary and operating segment.

As discussed below, in 2021 PSEG Power sold its solar facilities and entered into two agreements to sell PSEG Power’s 6,750 megawatts (MW) fossil generation asset portfolio. In February 2022, we completed the sale of this fossil generation portfolio which represented an important milestone in our strategy. See Item 8. Note 4. Early Plant Retirements/Asset Dispositions and Impairments for additional information. As a result, disclosures in this Item 1 and otherwise in this document that relate solely to this 6,750 MW fossil generation asset portfolio, except for those related to certain assets and liabilities excluded from the sale transactions, primarily for obligations under environmental regulations, including possible remediation obligations under the New Jersey Industrial Site Recovery Act and the Connecticut Transfer Act, are no longer relevant.

Over the past few years, our investments have altered our business mix to reflect a higher percentage of earnings contribution by PSE&G, which improves the sustainability and predictability of our earnings and cash flows. The sale of the fossil generating portfolio further alters our business mix, resulting in an even higher percentage of earnings contribution by PSE&G going forward and provides more financial flexibility.

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Our other direct wholly owned subsidiaries are: PSEG Energy Holdings L.L.C. (Energy Holdings), which holds our investments in offshore wind ventures and legacy portfolio of lease investments; PSEG Long Island LLC (PSEG LI), which operates the Long Island Power Authority’s (LIPA) electric transmission and distribution (T&D) system under a contractual agreement; and PSEG Services Corporation (Services), which provides us and our operating subsidiaries with certain management, administrative and general services at cost.

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 6.5 million people, or about 70% 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.

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

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In addition to our current utility products and services, we have implemented a set of programs to encourage conservation and energy efficiency by providing energy and cost-saving measures directly to businesses and families. Our largest program, Clean Energy Future, as described below, encompasses four programs (i) Energy Efficiency; (ii) Electric Vehicle make ready charging infrastructure; (iii) Energy Cloud and (iv) Energy Storage, three of which we began implementing in 2021.

We have also implemented several programs to invest in regulated solar generation within New Jersey, including programs to help finance the installation of solar power systems throughout our electric service area, and programs to develop, own and operate solar power systems.

How PSE&G Operates

We are a transmission owner in PJM Interconnection, L.L.C. (PJM) and we provide distribution service to 2.3 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 depreciation expense and deferred taxes (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 current approved rates provide for a base ROE of 9.90% and a 50 basis point adder for our membership in PJM as a Regional Transmission Operator (RTO). See Item 7. MD&A—Executive Overview of 2021 and Future Outlook.

We continue to invest in transmission projects that are included for review in the FERC-approved PJM transmission expansion process. These projects focus on reliability improvements and replacement of aging infrastructure with planned capital spending of $2.3 billion for transmission in 2022-2024 as disclosed in Item 7. MD&A—Capital Requirements.

Distribution

PSE&G distributes electricity and natural gas to end users in our respective franchised service territories. In October 2018, the BPU issued an Order approving the settlement of our distribution base rate proceeding with new rates effective November 1, 2018. The Order provides for a distribution rate base of $9.5 billion, a 9.60% ROE for our distribution business and a 54% equity component of our capitalization structure. The BPU has also approved a series of PSE&G infrastructure, energy efficiency, electric vehicle and renewable energy investment programs with cost recovery through various clause mechanisms. For a discussion of proposed and approved programs, see Clean Energy Future Program below and Item 7. MD&A—Executive Overview of 2021 and Future Outlook. Our load requirements are split among residential, C&I customers, as described in the following table for 2021:



	% of 2021 Sales
Customer Type	Electric	Gas
Commercial	56%	37%
Residential	35%	59%
Industrial	9%	4%
Total	100%	100%

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Our customer base has modestly increased since 2017, with electric and gas loads changing as illustrated in the following table:

Electric and Gas Distribution Statistics

December 31, 2021

Number of
Customers

Electric Sales and Firm Gas
Sales (A)

Historical Annual Load Growth 2017-2021

Electric

2.3

Million

40,163

Gigawatt hours (GWh)

(0.7)%

Gas

1.9

Million

2,422

Million Therms

0.5%

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

Electric sales declined due to the economic impact of the ongoing coronavirus pandemic (COVID-19) on commercial usage, greater conservation, more energy efficient appliances and increases in solar net metering installations, partially offset by an increase in residential sales due to a significant number of customers working from home during the pandemic and customer growth. Firm gas sales increased due to higher residential sales due to the pandemic, customer growth and customer response to continued low gas prices. 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 filing, we implemented the Conservation Incentive Program (CIP) that trues up PSE&G’s margin to a baseline per customer from our 2018 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.

Clean Energy Future (CEF) Program

We have launched three of the four components of our CEF program:

•Energy Efficiency (EE)—a $1 billion three-year commitment with the majority of the investment occurring over a five-year period, approved by the BPU in September 2020, is designed to achieve energy efficiency 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.

•Energy Cloud (EC)— a $707 million four-year investment, approved by the BPU in January 2021, driven by the implementation of “smart meters,” and new software and product solutions to improve our processes and better manage the electric grid.

•Electric Vehicle (EV)—a $166 million six-year investment, approved by the BPU in January 2021, 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. A remaining component of our program related to medium and heavy duty charging infrastructure has been the subject of a stakeholder process at the BPU.

Our CEF-Energy Storage program is being held in abeyance pending future policy guidance from the BPU. Our proposed Energy Storage 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.

For additional information on the recovery of revenues, capital costs and expenses related to the CEF program, see Item 7. MD&A—Executive Overview of 2021 and Future Outlook.

Solar Generation

We have undertaken two major solar initiatives at PSE&G, the Solar Loan Program and the Solar 4 All® Programs. Our Solar Loan Program provides solar system financing to our residential and commercial customers. The loans are repaid with cash or solar renewable energy certificates (SRECs). We sell the SRECs received through periodic auctions and use the proceeds to offset program costs. Our Solar 4 All® Programs invest in utility-owned solar photovoltaic (PV) grid-connected solar systems installed on PSE&G property and third-party sites, including landfill facilities, and solar panels installed on distribution system poles in our electric service territory. We sell the energy from the systems in the PJM wholesale electricity market. In addition, we sell SRECs generated by the projects through the same periodic auction used in the Solar Loan program, the proceeds of which are used to offset program costs. In both programs, our economics are driven by our net investment in solar, with a contemporaneous return on that rate base.

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Supply

Although commodity revenues make up almost 34% of our revenues, 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).

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 15. 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.

Markets and Market Pricing

Historically, there has been significant volatility in commodity prices. Such fluctuations can have a considerable impact on us since a rising commodity price environment results in higher delivered electric and gas rates for customers. This could result in decreased demand for electricity and gas, increased regulatory pressures and greater working capital requirements as the collection of higher commodity costs from our customers may be deferred under our regulated rate structure. A declining commodity price, on the other hand, would be expected to have the opposite effect.

PSEG Power

Through PSEG Power, we have sought to produce low-cost electricity by efficiently operating our nuclear and gas/oil-fired generation assets while balancing generation output, fuel requirements and supply obligations through energy portfolio management. 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 is also subject to certain regulatory requirements imposed by state utility commissions such as those in New York and Connecticut.

In June 2021, we completed the sale of PSEG Power’s solar portfolio. In August 2021, we entered into two agreements to sell PSEG Power’s 6,750 MW of fossil generation located in New Jersey, Connecticut, New York and Maryland to newly formed subsidiaries of ArcLight Energy Partners Fund VII, L.P., a fund controlled by ArcLight Capital Partners, LLC. In February 2022, we completed the sale of this fossil generation portfolio. See Item 8. Note 4. Early Plant Retirements/Asset Dispositions and Impairments for further discussion.

Products and Services

As a merchant generator, our revenue is derived from selling a range of products and services under contract to an array of customers, including utilities, power marketers, such as retail energy providers, or counterparties in the open market. These products and services may be transacted bilaterally or through exchange markets and include but are not limited to:

•Energy—the electrical output produced by generation plants that is ultimately delivered to customers for use in lighting, heating, air conditioning and operation of other electrical equipment. Energy is our principal product and is priced on a usage basis, typically in cents per kilowatt hour or dollars per megawatt hour (MWh).

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•Capacity—distinct from energy, capacity is a market commitment that a given generation unit will be available to an Independent System Operator (ISO) for dispatch to produce energy when it is needed to meet system demand. Capacity is typically priced in dollars per MW for a given sale period (e.g. day or month).

•Ancillary Services—related activities supplied by generation unit owners to the wholesale market that are required by the ISO to ensure the safe and reliable operation of the bulk power system. Owners of generation units may bid units into the ancillary services market in return for compensatory payments. Costs to pay generators for ancillary services are recovered through charges collected from market participants.

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 customers. In 2014, the BPU approved an extension of the long-term BGSS contract to March 31, 2019, and thereafter the contract remains in effect unless terminated by either party with a two-year notice.

Approximately 47% of PSE&G’s peak daily gas requirements is provided from PSEG Power’s firm gas transportation capacity. PSEG Power satisfies the remainder of PSE&G’s requirements from storage contracts, contract peaking supply, liquefied natural gas and propane. Based upon the availability of natural gas beyond PSE&G’s daily needs, PSEG Power sells gas to others and uses it for its generation fleet.

PSEG Power also has a 50% ownership interest in a 208 MW oil-fired generation facility in Hawaii.

The remainder of this section about PSEG Power covers our nuclear and fossil fleet which comprises the vast majority of PSEG Power’s operations and financial performance. For additional information, see Item 2. Properties.

How PSEG Power’s Generation Operates

Nearly all of our generation capacity is located in the Northeast and Mid-Atlantic regions of the United States in some of the country’s largest and most developed electricity markets.

•Capacity

As of December 31, 2021, PSEG Power had 10,638 MW of nuclear and fossil generation capacity, including the fossil assets Held for Sale. The sale of our 6,750 MW of fossil generation located in New Jersey, Connecticut, New York and Maryland was completed in February 2022. Effective May 31, 2021, PSEG Power retired its 383 MW coal unit in Bridgeport, Connecticut. PSEG Power has retired or exited all of its coal-fired generation.

•Generation Dispatch

Our generation units have historically been characterized as serving one or more of three general energy market segments: base load; load following; and peaking, based on their operating capability and performance.

•Base Load Units run the most and typically are called to operate whenever they are available. These units generally derive revenues from both energy and capacity sales. 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. Our nuclear generation is considered to be base load.

•Load Following Units’ operating costs are generally higher per unit of output than for base load units due to the use of higher-cost fuels such as oil and natural gas or lower overall unit efficiency. These units usually have more flexible operating characteristics than base load units which enable them to more easily follow fluctuations in load. They operate less frequently than base load units and derive revenues from energy, capacity and ancillary services.

•Peaking Units run the least amount of time. These units typically start very quickly in response to system needs. Costs per unit of output tend to be higher than for base load units given the combination of higher heat rates and fuel costs. The majority of revenues are from capacity and ancillary service sales. The characteristics of these units enable them to capture energy revenues during periods of high energy prices.

In the energy markets in which we operate, owners of power plants specify to the ISO prices at which they are prepared to generate and sell energy based on the marginal cost of generating energy from each individual unit. The ISOs will generally dispatch in merit order, calling on the lowest variable cost units first and dispatching progressively higher-cost units until the point that the entire system demand for power (known as the system “load”) is satisfied reliably. Base load units are dispatched first, with load following units next, followed by peaking units. It should be noted that the sustained lower pricing of natural gas over the past several years has resulted in changes in relative operating costs compared to historical norms, enabling some gas-fired generation to displace some generation by other fuel types. This change, combined with the addition of new, more

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efficient generation capacity, has altered the historical dispatch order of certain plants in the markets where we operate.

Typically, the bid price of the last unit dispatched by an ISO establishes the energy market-clearing price. After considering the market-clearing price and the effect of transmission congestion and other factors, the ISO calculates the Locational Marginal Price (LMP) for every location in the system. The ISO pays all units that are dispatched their respective LMP for each MWh of energy produced, regardless of their specific bid prices. Since bids generally approximate the marginal cost of production, units with lower marginal costs typically generate higher gross margins than units with comparatively higher marginal costs.

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 primary markets in which we operate.

Market wholesale prices may vary by location resulting from congestion or other factors, such as the availability of natural gas from the Marcellus (Leidy) and other shale-gas regions, 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.

Fuel Supply

•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.

•Gas Supply—Natural gas is the primary fuel for the bulk of our load following and peaking fleet. We purchase gas directly from natural gas producers and marketers. We have approximately 2.3 billion cubic feet-per-day of firm transportation capacity and firm storage delivery under contract to meet our obligations under the BGSS contract. This volume includes capacity from the Pennsylvania and Ohio shale gas regions where we purchase the majority of our natural gas. On an as-available basis, this firm transportation capacity may also be used to serve the gas supply needs of our New Jersey generation fleet. These supplies are transported to New Jersey by four interstate pipelines with which we have contracted. In addition, we hold year-round firm gas transportation capacity to serve the majority of the requirements of Keys Energy Center in Maryland.

•Oil—Oil is used as the primary fuel for one load following steam unit and four combustion turbine peaking units and can be used as an alternate fuel by several load following and peaking units that have a dual-fuel capability. Oil for operations is drawn from on-site storage and is generally purchased on the spot market and delivered by truck or barge.

We expect to be able to meet the fuel supply demands of our customers and 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, and other factors. For additional information and a discussion of risks, see Item 1A. Risk Factors, Item 7. MD&A—Executive Overview of 2021 and Future Outlook and Item 8. Note 15. Commitments and Contingent Liabilities.

Markets and Market Pricing

All of PSEG Power’s nuclear generation assets are located within the PJM RTO. PJM conducts the largest centrally dispatched energy market in North America. The PJM Interconnection coordinates the movement of electricity through all or parts of Delaware, Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia and the District of Columbia. PSEG Power’s fossil generation assets classified as Held for Sale as of December 31, 2021 are primarily located within PJM and also have operations within the New York ISO (NYISO) and New England (ISO-NE).

The Bethlehem Energy Center generating station operates in New York and our Bridgeport Harbor 5 and New Haven stations operate in Connecticut.

The price of electricity varies by location in each of these markets. Depending on our production and our obligations, these price differentials may increase or decrease our profitability.

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Commodity prices, such as electricity, gas, oil and environmental products, as well as the availability of our fleet of generation units to operate, have a considerable effect on our profitability. Over the long-term, the higher the forward prices are, the more attractive an environment exists for us to contract for the sale of our anticipated output. However, higher prices also increase the cost of replacement power; thereby placing us at greater risk should our generating units fail to operate effectively or otherwise become unavailable.

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 the ISO for dispatch at its discretion. Capacity payments reflect the value to the ISO of assurance that there will be sufficient generating capacity available at all times to meet system reliability and energy requirements. See Item 7. MD&A—Executive Overview of 2021 and Future Outlook—Wholesale Power Market Design.

In PJM and ISO-NE, where we operate most of our generation, the market design for capacity payments provides for a structured, forward-looking, capacity pricing mechanism through the Reliability Pricing Model (RPM) in PJM and the Forward Capacity Market (FCM) in ISO-NE. 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. For each delivery year, the prices differ in the various areas of PJM, depending on the transfer limitations of the transmission system in each area.

Our PJM generating units are located in several zones. The average capacity prices that PSEG Power expects to receive from the base and incremental auctions which have been completed are disclosed in Item 8. Note 3. Revenues. The price that must be paid by an entity serving load in the various capacity zones is also set through these auctions. These prices can be higher or lower than the prices disclosed in Item 8. Note 3. Revenues due to the import and export capability to and from lower-priced areas.

We have obtained price certainty for our PJM capacity through May 2023 through the RPM pricing mechanism and New England capacity through May 2025 for New Haven through the FCM pricing mechanism.

Like PJM and ISO-NE, the NYISO provides capacity payments to its generating units, but unlike the other two markets, the New York market does not provide a forward price signal beyond a six-month auction period.

For additional information on the RPM and FCM markets, as well as on state subsidization through various mechanisms, see Regulatory Issues—Federal Regulation.

Hedging Strategy

To mitigate volatility in our results, we seek to contract in advance for a significant portion of our anticipated electric output, capacity and fuel needs. We seek to sell a portion of our anticipated lower-cost generation over a multi-year forward horizon, normally over a period of two to three years. We believe this hedging strategy increases the stability of earnings.

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 generation related products. 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 merchant power business. While this limits our exposure to decreasing prices, our ability to realize benefits from rising market prices, as experienced in 2021, is also limited. Therefore, our realized prices in 2021 were significantly lower than market pricing due to forward sales contracts executed in prior years for delivery in 2021. For this same reason, expected realized prices in forward periods will also have limited benefits from the recent rise in forward market prices.

We ceased entering into new full requirements contracts as a hedging strategy due to the sale of the fossil generation assets. In addition, we ceased hedging the fossil generation assets in 2022 due to the sale. As defined in the sales agreements, any positive or negative cash flow from the fossil generating assets based on actual performance starting after December 31, 2021 will result in an adjustment to the purchase price. See Item 8. Note 4. Early Plant Retirements/Asset Dispositions and Impairments for more information.

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 2022 and a significant portion through 2023.

More than 90% of PSEG Power’s expected gross margin in 2022 from the expected remaining generation assets after the sale of the fossil generation portfolio relates to our hedging strategy, our expected revenues from the capacity market mechanisms

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described above, Zero Emission Certificate (ZEC) revenues and certain gas operations and ancillary service payments such as reactive power.

The contracted percentages of our anticipated base load generation output for the next three years are as follows:



Base Load Generation	2022	2023	2024
Generation Sales	95%-100%	85%-90%	45%-50%

Energy Holdings

Energy Holdings maintains our interests in offshore wind as well as a portfolio of domestic lease investments. See Item 8. Note 9. Long-Term Investments and Note 10. Financing Receivables for additional information.

Offshore Wind

In December 2020, PSEG entered into a definitive agreement with Ørsted North America Inc. (Ørsted) to acquire a 25% equity interest in Ørsted’s Ocean Wind project. Ocean Wind was selected by New Jersey to be the first offshore wind farm as part of the State’s intention to add 7,500 MW of offshore wind generating capacity by 2035. The Ocean Wind project is expected to achieve full commercial operation in 2025. On March 31, 2021, the BPU approved PSEG’s investment in Ocean Wind and the acquisition was completed in April 2021. 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 and Ørsted are exploring further opportunities to develop the remaining GSOE lease area. For information on potential additional offshore wind projects, see Item 7. MD&A—Executive Overview of 2021 and Future Outlook.

LIPA Operations Services Agreement

In accordance with a twelve year Operations Services Agreement (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. PSEG LI uses its brand in the Long Island T&D service area. Under the OSA, PSEG LI acts as LIPA’s agent in performing many of its obligations and in return (a) receives reimbursement 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. An amendment to the OSA was negotiated in 2021 and is pending approval by the New York State Comptroller. See Item 7. MD&A—Executive Overview of 2021 and Future Outlook.

COMPETITIVE ENVIRONMENT

PSE&G

Our T&D business is not affected when customers choose alternate electric or gas suppliers since we earn our return by providing 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 energy efficiency programs to help customers use less energy and investment programs to build EV infrastructure and solar generation. 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, 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, with several jurisdictions setting targets to move new construction to be exclusively electric. 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, resulting 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 to our current period revenue as compared to revenue thresholds established in our most

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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 in the current policies for building new transmission lines, such as those ordered by FERC and being implemented by PJM and other ISOs to eliminate contractual provisions that previously provided us a “right of first refusal” to construct 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. 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:

•merchant generators,

•domestic and multi-national utility generators,

•energy marketers and retailers,

•private equity firms, banks and other financial entities,

•fuel supply companies, and

•affiliates of other industrial companies.

New additions of lower-cost or more efficient generation capacity, as well as subsidized generation capacity, could make our plants less economic in the future. Such capacity could impact market prices and our competitiveness.

Our business is also under competitive pressure due to demand-side management (DSM) and other efficiency efforts aimed at changing the quantity and patterns of usage by consumers which could result in a reduction in load requirements. A reduction in load requirements can also be caused by economic cycles, weather and climate change, municipal aggregation and other customer migration and other factors. In addition, how resources such as demand response and capacity imports are permitted to bid into the capacity markets also affects the prices paid to generators such as PSEG Power in these markets. It is also possible that advances in technology, such as distributed generation and micro grids, will reduce the cost of alternative methods of producing electricity to a level that is competitive with that of most central station electric production. To the extent that additions to the electric transmission system relieve or reduce limitations and constraints in eastern PJM where most of our plants are located, our revenues could be adversely affected. Changes in the rules governing what types of transmission will be built, who is selected to build transmission and who will pay the costs of future transmission could also impact our generation revenues.

Adverse changes in energy industry law, policies and regulation could have significant economic, environmental and reliability consequences. For example, PJM, NYISO and ISO-NE each have capacity markets that have been approved by FERC. FERC regulates these markets and continues to examine whether the market design for each of these three capacity markets is working optimally. Various forums are considering how the competitive market framework can incorporate or be reconciled with state public policies that support particular resources, resource attributes or emerging technologies, whether generators are being sufficiently compensated in the capacity market and whether subsidized resources may be adversely affecting capacity market prices. For information regarding recent actions by FERC relating to capacity market design, see the discussion in Regulatory Issues—Federal Regulation.

Environmental issues, such as restrictions on emissions of carbon dioxide (CO2) and other pollutants, may also have a competitive impact on us to the extent that it becomes more expensive for some of our plants to remain compliant, thus affecting our ability to be a lower-cost provider compared to competitors without such restrictions. In addition, most of our plants, which are located in the Northeast where rules are more stringent, can be at an economic disadvantage compared to our competitors in certain Midwest states.

While it is our expectation that continued efforts may be undertaken by the federal and state governments to preserve the existing base nuclear generating plants, we still believe that pressures from renewable resources will continue to increase.

HUMAN CAPITAL MANAGEMENT

At PSEG, our workforce is essential in delivering on our business objectives. Our human capital management strategy is integrated with our overall environmental, social, and governance (ESG) leadership objectives and is designed to attract, develop, and retain a high performing workforce and evolve our culture to sustain our business, both today and in the future. PSEG maintains a consistent focus on a culture of inclusion and operational excellence that supports its employees, customers

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and the many diverse communities we serve. Our workforce is guided by our core commitments of safety, integrity, diversity, equity and inclusion (DEI), customer service and continuous improvement.

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 DEI, workforce development and succession planning.

PSEG has a fundamental commitment to human rights and as a responsible corporate citizen and leader in the energy field, we remain steadfast in our commitment to treating people with dignity and respect at all times. We are determined to maintain the high standards of ethical conduct on which our business and reputation have been built. In every aspect of our operations, we are committed to protecting and advancing human rights.

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

In 2021, of our external hires, 19% were women and 31% were racially and/or ethnically diverse. PSEG’s workforce is stable with a voluntary attrition rate of 6.0%. Retirement comprises the majority of that figure, occurring at a rate of 3.7% with resignation making up the remaining 2.3%. The average employee tenure is 14 years.

Health and Safety

We are committed to protecting the health and safety of our employees, contractors and the communities that we serve. We demonstrate our commitment each day by providing the tools and skill building needed to ensure employees are able to perform their work safely. Every employee is empowered and encouraged to question, stop and correct any unsafe act or condition while communicating openly and honestly on health and safety issues. In the event that there is a safety issue, our employees take responsibility for the accurate, honest, and timely reporting of all incidents and injuries. To hold ourselves accountable, we have annual performance goals related to compliance with health and safety policies, practices and procedures. PSEG’s Occupational Safety and Health Administration (OSHA) Recordable Incident Rate decreased from 0.85 in 2020 to 0.70 in 2021 and the OSHA Days Away from Work Rate also decreased from 12.68 in 2020 to 5.63 in 2021. Both metrics are top decile performance against the industry benchmark.

Culture, Diversity, Equity and Inclusion

We are committed to fostering a culture of belonging and equity, where diversity is celebrated and inclusion is the norm. The four strategic pillars of our DEI program are inclusive leadership, driving change at the site-specific level, equitable policies and practices and union partnership. In 2021, PSEG released its first DEI report providing transparent disclosures on the company’s Inclusion for All strategy and initiatives, including launching Neurodiversity Works, a program to provide access to employment at PSEG for neurodivergent individuals, publishing a formal LGBTQ+ Inclusion Pledge and job creation programs with worker diversity goals and commitments for supplier diversity.

Our Employee Business Resource Groups support key business goals and priorities; help build meaningful connections through community outreach and volunteerism, mentorship and professional development; elevate diverse perspectives; and create spaces for employees to learn from each other.

To measure the effectiveness of our DEI and workplace culture efforts, we continuously solicit feedback from employees through focus groups, listening sessions throughout the year and our annual Your Voice Matters employee experience survey. Employee engagement scores for 2021 averaged 84%, indicating employees are proud to work at PSEG, had meaningful work and intend to stay.

Talent, Attraction, Development and Engagement

From our frontline employees to our leadership roles, PSEG has maintained an unwavering focus on attracting, developing and retaining a robust talent pipeline to remain competitive and to continue to provide our customers with the highest standard of service.

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PSEG’s relationships with minority-serving institutions, trade schools and community partners attract a skilled workforce that reflects the communities we serve and all dimensions of diversity represented in those communities, including race, ethnicity, disability, parental status, LGBTQ+, and those with socioeconomic challenges.

Our employees grow through a variety of training and development opportunities at all career tracks within the organization and we invest in technical and operational training for our craft and field workers to support safe and reliable operations. We utilize data-driven workforce planning and succession processes to identify and develop diverse talent pools for critical technical and leadership positions.

As we accelerate our business to a primarily regulated utility and contracted energy business with carbon-free generation and infrastructure investment, PSEG is committed to a fair, equitable and transparent approach to human capital management, one that is grounded in treating people with dignity and respect. With evolving technologies in energy and digital advancements, we look for training, upskilling and redeployment opportunities for our existing workforce.

Total Rewards

In addition to our competitive pay, incentives, and health, welfare and retirement programs, our Total Rewards offerings consider the safety and overall well-being of our employees. We offer an array of programs designed to support physical, emotional, and financial wellness. Our programs include access to therapy, childcare and eldercare resources, voluntary benefits for discounted services, tuition reimbursement and adoption assistance.

Labor Relations

We are proud of the partnership we have with union leadership and the approximately 7,900 employees represented by unions in our workforce. Our strong relationship with our unions allowed for swift and effective implementation of temporary COVID-19 protocols, policies and practices, as well as negotiation of permanent agreements, such as telecommuting that support PSEG’s reimagined vision of more flexible work. In 2021, we launched our Union DEI & Culture Council to focus on issues impacting represented employees and improving the workplace culture at PSEG. In 2021, we also extended additional labor contracts through 2023, providing labor stability during the pendency of key business initiatives.

COVID-19 Response for Our Employees

We continued to anticipate and respond to changing circumstances in year two of the pandemic. In addition to remote work and enhanced benefits enacted in 2020, during 2021 employees were assisted in scheduling vaccination appointments and were provided on-site vaccination at various locations. All employees hired after October 2021 are required to be vaccinated subject to certain accommodation exceptions. We provide COVID-19 related paid time off for employees to take care of themselves and their family members, to get vaccinated, recover from side effects of the COVID-19 vaccine, to navigate school and daycare closures and for bereavement. We also implemented changes to medical and retirement savings plans made available through federal relief packages. PSEG’s Medical and Health and Safety team continues to provide consistent, up-to-date information to educate employees on current conditions.

The pandemic response hotline that was put in place in 2020 continued to provide up-to-date guidance to employees addressing questions about their COVID-19-related health and safety, providing identification and notification of close contact exposure, and offering clinical assessments to determine quarantine needs and appropriate return-to-work procedures.

In September 2021, PSEG opened offices for voluntary re-entry, as part of providing a sustained, reimagined way of working that is supported by a set of practices that enable us to work, live and hire responsibly. As COVID-19 conditions evolve, PSEG continues to monitor Centers for Disease Control and Prevention and OSHA guidance and updates its Job Hazard Analyses and protocols accordingly in order to protect our employees and the communities we serve.

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 15. Commitments and Contingent Liabilities. In addition, information regarding PSE&G’s specific filings pending before the BPU is discussed in Item 8. Note 7. 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 the generation and energy trading 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

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corporate reorganizations.

FERC also regulates RTOs/ISOs, such as PJM, and their energy and capacity markets.

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 & Trade LLC, PSEG Nuclear LLC and PSE&G, must file at FERC every three years to update their market power analyses with FERC.

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. 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 hour.

Over the past few years, PSEG has advocated for enhanced price formation rules in PJM so that generators receive better price signals in the energy market. An example of such an improvement has been in the area of fast-start pricing. Specifically, over the past two years, FERC ordered, and PJM then fully implemented as of September 2021, rules that allow fast-start resources with quick ramping capability to set prices in the energy market.

In May 2020, FERC issued an order approving PJM’s proposal to modify the curves used for pricing reserves with FERC. However, in December 2021, FERC determined that certain aspects of PJM’s reserve reforms, in particular the reserve penalty factors and the two-step operating reserve demand curves were unjust and unreasonable. As a result, generators would not receive higher revenues associated with the mechanisms proposed by PJM. Given FERC’s finding, FERC reinstated the backward-looking energy and ancillary services offset which is an input in capacity offer bids. As a result, FERC directed PJM to propose a new auction schedule for the upcoming base residual auction. In February, FERC approved PJM’s filing requesting that the auction be held in June 2022.

In January 2020, New Jersey rejoined the Regional Greenhouse Gas Initiative (RGGI). As a result, generating plants operating in New Jersey that emit CO2 emissions will have to procure credits for each ton that they emit. Other PJM states in RGGI are Maryland, Delaware and Virginia and Pennsylvania continues to investigate joining. PJM initiated a process in 2019 to investigate the development of a carbon pricing mechanism to mitigate the environmental and financial distortions that could occur when emissions “leak” from non-participating states to the RGGI states. PJM has halted the process. Proposals to consider the incorporation of environmental attributes into the market are now being addressed as part of PJM’s capacity market design reform efforts.

Capacity Market Issues

PJM, NYISO and ISO-NE each have capacity markets that have been approved by FERC. FERC regulates these markets and continues to examine whether the market design for each of these three capacity markets is working optimally. Various forums are considering how the competitive market framework can incorporate or be reconciled with state public policies that support particular resources, resource attributes or emerging technologies, whether generators are being sufficiently compensated in the capacity market and whether subsidized resources may be adversely affecting capacity market prices. We cannot predict what action, if any, FERC might take with regard to capacity market designs.

PJM—The RPM is the locational installed capacity market design for the PJM region, including 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 December 2019, FERC issued an order establishing new rules for PJM’s capacity market. In this new order, FERC extended the PJM Minimum Offer Price Rule (MOPR), which currently applies to new natural gas-fired generators, to include both new and existing resources that receive or are entitled to receive certain out-of-market payments, with certain exemptions.

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was not able to act on PJM’s proposed changes to the MOPR because of a split among the Commissioners on the lawfulness of PJM’s proposal. Therefore, PJM’s rules became automatically effective as of September 29, 2021 and will apply to the next base residual auction, which has been delayed until June 2022.

In November 2021, a group of generators challenged the new MOPR rules in the Court of Appeals for the Third Circuit on the grounds that FERC’s inaction was unlawful. PSEG has intervened in the proceeding in support of the new MOPR rules. We cannot predict the outcome of this proceeding.

In another order related to the auction, FERC found that the current rules related to the Market Seller Offer Cap were unjust and unreasonable and ultimately eliminated the default offer cap. In its place, FERC adopted a unit-specific approach to reviewing certain capacity market offers. These new rules could result in lower capacity prices for other market participants, including PSEG, and therefore, lower revenues for PSEG since market offers for many resource types will need to be approved by the Independent Market Monitor and PJM.

ISO-NE—ISO-NE’s market for installed capacity in New England provides fixed capacity payments for generators, imports and demand response. The market design consists of a forward-looking auction for installed capacity that is intended to recognize the locational value of resources on the system and contains incentive mechanisms to encourage availability during stressed system conditions. ISO-NE also employs a mechanism, similar to PJM’s Capacity Performance mechanism, that provides incentives for performance and that imposes charges for non-performance during times of system stress. We view this mechanism as generally positive for generating resources as providing more robust income streams. However, it also imposes additional financial risk for non-performance.

NYISO—NYISO operates a short-term capacity market that provides a forward price signal only for six months into the future. Various matters pending before FERC could affect the competitiveness of this market and the outcome of these proceedings could result in artificial price suppression for PSEG and other market participants unless sufficient market protections are adopted.

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 October 2021, FERC approved a settlement agreement effective August 1, 2021 between PSE&G, the BPU and the New Jersey Division of Rate Counsel (New Jersey Rate Counsel) related to the level of PSE&G’s base transmission ROE and other formula rate matters. The settlement reduces PSE&G’s base ROE from 11.18% to 9.9% and makes several other changes regarding the recovery of certain costs. The agreement provides that the settling parties will not seek changes to PSE&G’s transmission formula rate for three years. We have implemented the terms of the agreement and PJM issued refunds to customers in January 2022.

In a rulemaking proceeding, FERC has 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 could reduce PSE&G’s annual Net Income and annual cash inflows by approximately $30 million-$40 million.

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 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. This standard supplements the Critical Infrastructure Protection standards that are already in place and that establish physical and cybersecurity protections for critical systems. FERC directed NERC to develop a new reliability standard to provide security controls for supply chain management associated with the procurement of industrial control system hardware, software, and services related to grid operations. FERC approved the supply chain management standard in October 2018, with an implementation date of October 1, 2020. We have documented procedures and implemented new processes to comply with these standards.

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The NERC is currently examining revised criteria for low-impact cyber systems, which could result in expanding the Critical Infrastructure Protection standards to a larger set of applicable cyber assets. This examination is expected to be completed in 2022.

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 systemic 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 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 nuclear generating unit may operate. The NRC conducts ongoing reviews of nuclear industry operating 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.

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						2053
			Peach Bottom Unit 3						2054

State Regulation

Our principal state regulator is the BPU, which oversees electric and natural gas distribution companies (GDCs) 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. PSE&G’s participation in solar, EV and energy efficiency 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.

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.

New Jersey Energy Master Plan (EMP)—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 State’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 EMP outlines several strategies, including statewide energy efficiency 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. We cannot predict the impact on our business or results of operations from the EMP or any laws, rules or regulations promulgated as a result thereof, particularly as they may relate to PSEG Power’s nuclear and gas generating stations and PSE&G’s electric transmission and gas distribution assets. We also cannot predict what actions federal government

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agencies may take in light of the Environmental Protection Agency’s (EPA) Affordable Clean Energy (ACE) rule and other federal initiatives associated with climate change or the impact of any such actions on our business or results of operations.

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 conducted public hearings. PSE&G and other interested parties answered the BPU’s questions regarding capacity procurement (e.g. timing, price, sufficiency); the sufficiency of New Jersey’s pipeline capacity; cost impacts if GDCs were to be required to secure incremental capacity for their transportation customers; and economic benefits to residential customers. The consultant’s November 2021 report found that through 2030, firm gas capacity can meet firm demand under normal winter weather conditions. In extreme weather, the consultant projected a system shortfall by 2030, unless New Jersey meets half of its building electrification goals and/or has effective voluntary demand reduction with higher energy efficiency program targets. The BPU may hold additional meetings to develop recommendations. The proceeding remains open.

BGS Process—In July 2021, the State’s electric distribution companies (EDCs), including PSE&G, filed their annual proposal for the conduct of the February 2022 BGS auction covering energy years 2023 through 2025. In prior years, the BPU and BGS suppliers had expressed concerns regarding transmission costs incurred by BGS participants that are collected from customers but not paid to the BGS suppliers due to several unresolved proceedings at FERC. To address these concerns, in their July 2020 BGS filings, the EDCs proposed, among other things, to (a) remove transmission from the BGS product in the upcoming 2021 BGS auction, and (b) amend existing BGS contracts to transfer responsibility for transmission-through the transfer of specific PJM billing line items-from the BGS supplier to the EDCs. In both cases, each EDC would continue to collect transmission costs from its BGS customers as a supply cost. In November 2020, the BPU approved both proposals. As a result, beginning with the 2021 BGS auction, (a) the BGS product excluded the obligation for the BGS suppliers to provide transmission and (b) BGS suppliers had the option to amend existing BGS contracts to transfer the supplier’s obligation to provide transmission to the EDCs effective February 1, 2021. In November 2020, the BPU also directed the EDCs to enter into agreements with BGS suppliers pursuant to which the EDCs would pay to BGS suppliers certain funds collected from BGS customers notwithstanding the absence of final FERC Orders in certain cases in which transmission cost allocations have been challenged. Previously, the EDCs had collected these funds from customers but withheld payment of these funds to BGS suppliers until the issuance of a final FERC Order. As security to the EDCs, in the event that the cost allocation challenges are ultimately successful and BGS suppliers must return the funds to the EDCs, the BGS suppliers must post a letter of credit in an amount equal to 50% of the payment due the suppliers. Those BGS suppliers that do not choose to receive such funds are not required to enter into agreements or post letters of credit with the EDCs.

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 a 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. 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 has retained a consultant that is gathering detailed and comprehensive information from the State’s EDCs, including PSE&G, regarding resource issues and policy changes needed to interconnect the clean energy capacity required under state policy. 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—Pursuant to the Clean Energy Act, the BPU was required to undertake several initiatives in connection with New Jersey’s solar energy market.

In 2019, the BPU established a “Community Solar Energy Pilot Program,” permitting customers to participate in solar energy projects remotely located from their properties, and allowing for bill credits related to that participation. Still pending with the BPU are certain issues, including minor modifications to the community solar pilot program, discussions regarding the potential implementation of consolidated billing for the benefit of project developers and participants, and development of a cost recovery mechanism for the EDCs.

The Clean Energy Act required the BPU to close the then-existing SREC program to new applications at the earlier of June 1, 2021 or the date at which 5.1% of New Jersey retail electric sales are derived from solar. The 5.1% threshold was attained and the SREC market was closed to new applications on April 30, 2020, with limited exceptions related to the impact of COVID-19 on projects under development. Solar projects that failed to achieve commercial operation before April 30, 2020 may be entitled to receive transition renewable energy certificates (TRECs) for each MWh of solar production. The New Jersey EDCs,

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including PSE&G, are required to purchase, using the services of a TREC administrator, TRECs from solar projects at rates set by the BPU.

In July 2021, the BPU issued an order formally establishing the Successor Solar Incentive (SuSI) Program, heavily drawing upon the predecessor TREC program, to serve as the permanent program for providing solar incentives to qualified solar electric generation facilities. The program provides for incentive payments at prices established in the BPU’s July 2021 order in the form of Solar Renewable Energy Certificates (SREC-IIs) for each MWh generated by net-metered projects of 5 MW or less, and an annual competitive solicitation to establish SREC-II prices applicable to grid-supply projects and net-metered projects in excess of 5 MW. The State’s EDCs have retained an administrator to acquire all of the SREC-IIs received each year by eligible solar generation projects. Each EDC, in turn, may recover from its customers the reasonable and prudent costs for SREC-II procurement and SREC-II administrator fees, based on its proportionate share of retail electric sales, and other costs reasonably and prudently incurred in the disposition of its SuSI obligations. The SuSI Program commenced on August 28, 2021.

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 information systems. The Board of Directors, the Audit Committee, Industrial Operations Committee and senior management receive 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.

Our cybersecurity program is focused on the following areas:

•Governance

•Cybersecurity Council—which is comprised of members of senior management, meets regularly to discuss emerging cybersecurity issues and maintenance of a corporate cybersecurity scorecard to measure performance of key risk indicators. The Cybersecurity Council ensures that senior management, and ultimately, the Board, is given the information required to exercise proper oversight over cybersecurity risks and that escalation procedures are followed.

•Internal and external cybersecurity advisors who have expertise in technology security, compliance and controls, or in management practices provide the Chief Operating Officer with periodic cybersecurity assessments of PSEG.

•Training—Providing 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 conducting phishing exercises. Regular cybersecurity education is also provided to our Board through management reports and presentations by external subject matter experts.

•Technical Safeguards—Deploying measures to protect our network perimeter and internal Information Technology platforms, such as internal and external firewalls, network intrusion detection and prevention, penetration testing, vulnerability assessments, threat intelligence, anti-malware and access controls.

•Vendor Management—Maintaining a risk-based vendor management program, including the development of robust security contractual provisions. Notably, in 2020, we implemented additional measures to ensure compliance with new requirements promulgated by the NERC applicable to cyber systems involved in the operation of the Bulk Electric System (BES). These new or enhanced measures require PSEG to identify and assess risks to the BES from vendor products or services.

•Incident Response Plans—Maintaining and updating incident response plans that address the life cycle of a cybersecurity incident from a technical perspective (i.e., detection, response, and recovery), as well as data breach response (with a focus on external communication and legal compliance); and testing those plans (both internally and through external exercises).

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

PSEG also maintains physical security measures to protect its Operational Technology 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

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advisory system, a business interruption management model, and active coordination with federal, state, and local law enforcement officials. See Regulatory Issues—Federal Regulation for a discussion on physical reliability standards that the NERC has promulgated.

In addition, we are subject to federal and state requirements designed to further protect against cybersecurity threats to critical infrastructure, as discussed below. For a discussion of the risks associated with cybersecurity threats, see Item 1A. Risk Factors.

Federal—NERC, at the direction of FERC, has implemented national and regional reliability standards to ensure the reliability of the grid and to prevent major system blackouts. NERC Critical Infrastructure Protection standards establish cybersecurity protections for critical systems and facilities. These standards are also designed to develop coordination, threat sharing and interaction between utilities and various government agencies regarding potential cyber threats against the nation’s electric grid.

The Transportation Security Administration, an agency of the U.S. Department of Homeland Security (DHS), issued two security directives in 2021 designed to mitigate cybersecurity threats to natural gas pipelines. The first security directive requires pipeline owners/operators to (i) report actual and potential cybersecurity incidents to the Cybersecurity and Infrastructure Security Agency, a DHS agency; (ii) designate a “Cybersecurity Coordinator;” (iii) review their current cybersecurity practices; and (iv) identify any gaps and related remediation measures to address cyber-related risks. The second security directive requires pipeline owners/operators to (i) implement specific mitigation measures to protect against cyber threats; (ii) implement a cybersecurity contingency and recovery plan; and (iii) conduct a cybersecurity architecture design review.

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. 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 pollution control equipment, hazardous substance liabilities and fuel and waste disposal costs, see Item 1A. Risk Factors and Item 8. Note 15. Commitments and Contingent Liabilities.

Air Pollution Control

Our facilities are subject to federal regulation under the Clean Air Act (CAA) that requires controls of emissions from sources of air pollution and imposes recordkeeping, reporting and permit requirements. Our facilities are also subject to requirements established under state and local air pollution laws. The CAA requires all major sources, such as our generation facilities, to obtain and keep current an operating permit. The costs of compliance associated with any new requirements that may be imposed and included in these permits in the future could be material and are not included in our estimates of capital expenditures.

Environmental Justice—In September 2020, the New Jersey governor signed legislation that enacted an environmental justice process for applicants seeking environmental permits, including those emission permits regulated under Title V of the CAA, for facilities located in what the law defines as overburdened communities. In September 2021, the New Jersey Department of Environmental Protection (NJDEP) issued an administrative order requiring an environmental justice review of certain permit applications pursuant to the New Jersey Environmental Justice (EJ) Law. The order will remain in effect until implementing regulations under the EJ Law are promulgated, which are expected to be issued as early as Spring 2022. The impacts of the NJDEP’s action are being evaluated for both PSE&G and PSEG Power and the outcome cannot be determined at this time.

Hazardous Air Pollutants (HAPS) Regulation—In February 2012, the EPA published Mercury Air Toxics Standards (MATS) for both newly-built and existing electric generating sources under the National Emission Standard for Hazardous Air Pollutants provisions of the CAA. The MATS established allowable levels for mercury as well as other HAPS and went into effect in April 2015. In April 2016, the EPA released the final Supplemental Finding that considers the materiality of costs in

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determining whether to regulate HAPS from power plants in response to a ruling by the U.S. Supreme Court. The 2016 Supplemental Finding determined that HAPS from existing electric generating units should be regulated and that the environmental and health benefits derived from the reduction in emissions of both HAPS and co-benefit pollutants far outweighed the cost of compliance. Industry participants and various state authorities filed petitions with the D.C. Circuit challenging the EPA’s Supplemental Finding.

In May 2020, the EPA finalized a revised Supplemental Finding that reversed the 2016 Supplemental Finding, concluding that it was not “appropriate and necessary” to regulate HAPS from electric generating sources. However, the EPA retained the emission standards and other requirements of MATS. A major coal mining company filed a lawsuit to force the EPA to vacate MATS. We have filed as intervenors to the coal mining company’s suit to challenge the company’s attempt to vacate MATS. In addition, we have joined a challenge against the EPA’s revised Supplemental Finding in the D.C. Circuit Court. In January 2022, the EPA released a proposed rule that would reverse the May 2020 Supplemental Finding. We cannot predict the outcome of this matter.

Climate Change

CO2 Regulation under the CAA—In June 2019, the EPA issued its final ACE rule as a replacement for the repealed Clean Power Plan, a greenhouse gas (GHG) emission regulation for existing power plants. The ACE rule narrowly defines the “best system of emissions reductions” (BSER) as heat improvements to be applied only to an individual unit, excluding other potential mechanisms to address climate change. In September 2019, a coalition of power companies, including PSEG, filed a Petition for Review of the ACE rule with the D.C. Circuit challenging the EPA’s narrow interpretation of BSER. In January 2021, the D.C. Circuit vacated the ACE rule and remanded the rulemaking to the EPA for further consideration. In April 2021, a 19-state coalition, led by West Virginia, filed a petition with the U.S. Supreme Court to review the D.C. Circuit’s decision to vacate the ACE Rule. In October 2021, the U.S. Supreme Court agreed to review the 2021 D.C. Circuit’s decision vacating the ACE Rule. We cannot predict the outcome of this matter or estimate its impact on our business or results of operations.

RGGI—Certain northeastern states (RGGI States) participate in the RGGI and have state-specific rules in place to enable the RGGI regulatory mandate in each state to cap and reduce CO2 emissions. Generating plants operating in RGGI states that emit CO2 will have to procure credits for each ton that they emit. The post-2020 program cap on regional CO2 emissions for RGGI requires a decline in CO2 emissions in 2021 and each year thereafter, resulting in a 30% reduction in the CO2 emissions cap by 2030.

In June 2019, the NJDEP issued two rules that began New Jersey’s re-entry into RGGI. The first rule established New Jersey’s initial cap on GHG emissions of 18 million tons in 2020. This rule follows the RGGI model rule with a cap that will decline three percent annually through 2030 to a final cap of 11.5 million tons. The second rule established the framework for how credits will be allocated among the New Jersey Economic Development Authority, the BPU and the NJDEP. In April 2020, the State issued a final three-year Strategic Funding Plan that determines how quarterly RGGI credits are to be allocated. New Jersey facilities became subject to RGGI on January 1, 2020. With New Jersey’s re-entry into RGGI, we have generation facilities in four of the RGGI States, specifically New Jersey, New York, Maryland and Connecticut.

New Jersey adopted the Global Warming Response Act in 2007, which calls for stabilizing its GHG emissions to 1990 levels by 2020, followed by a further reduction of greenhouse emissions to 80% below 2006 levels by 2050. To reach this goal, the NJDEP, the BPU, other state agencies and stakeholders are required to evaluate methods to meet and exceed the emission reduction targets, taking into account their economic benefits and costs. Following the close on the sale of the fossil generating assets, PSEG no longer has generation subject to the RGGI compliance requirements.

New Jersey Protecting Against Climate Threats (NJ PACT)—In response to a New Jersey Executive Order, the NJDEP has undertaken a regulatory reform effort that is designed to modernize environmental laws, referred to as NJ PACT. When implemented, NJ PACT is expected to result in changes to existing environmental regulation, modernizing air quality and environmental land use regulations that will enable governments, businesses and residents to effectively respond to current climate threats and reduce future climate damages. In June 2021, the NJDEP took the first step by publishing the Proposed Greenhouse Gas Monitoring and Reporting Rule. The NJDEP proposes to require gas utilities to submit an annual report on replacement of mains and service lines in the State and to quantify maintenance-venting events, referred to as blowdown events. In addition, the NJDEP is proposing registration, recordkeeping, and reporting requirements for facilities with a refrigeration system requiring 50 pounds or more of a refrigerant with high global warming potential. A “refrigeration system” includes industrial process refrigeration utilized at our nuclear facility. We continue to assess the potential impact of the NJ PACT, which could have cost implications for business operations, including the construction of new facilities or upgrades to existing utility infrastructure. Such expenditures could materially affect the continued economic viability and/or cost to construct one or more such facilities.

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Water Pollution Control

The Federal Water Pollution Control Act (FWPCA) prohibits the discharge of pollutants to U.S. waters from point sources, except pursuant to a National Pollutant Discharge Elimination System (NPDES) permit issued by the EPA or by a state under a federally authorized state program. The FWPCA authorizes the imposition of technology-based and water quality-based effluent limits to regulate the discharge of pollutants into surface waters and ground waters. The EPA has delegated authority to a number of state agencies, including those in New Jersey, New York and Connecticut, to administer the NPDES program through state action. We also have ownership interests in facilities in other jurisdictions that have their own laws and implement regulations to control discharges to their surface waters and ground waters.

The EPA’s Clean Water Act (CWA) Section 316(b) rule establishes requirements for the regulation of cooling water intakes at existing power plants and industrial facilities with a design flow of more than two million gallons of water per day. The EPA requires that the NPDES permits be renewed every five years and that each state Permitting Director manage renewal permits for its respective power generation facilities on a case by case basis. The NJDEP manages the permits under the New Jersey Pollutant Discharge Elimination System program. Connecticut and New York also have permits to manage their respective pollutant discharge elimination system programs.

Hazardous Substance Liability

The production and delivery of electricity and the distribution and manufacture of gas result in various by-products and substances classified by federal and state regulations as hazardous. These regulations may impose liability for damages to the environment, including obligations to conduct environmental remediation of discharged hazardous substances and monetary payments, regardless of the absence of fault, any contractual agreements between private parties, and the absence of any prohibitions against the activity when it occurred, as well as compensation for injuries to natural resources. Our historic operations and the operations of hundreds of other companies along the Passaic and Hackensack Rivers are alleged by federal and state agencies to have discharged substantial contamination into the Passaic River/Newark Bay Complex. The EPA is also evaluating the Hackensack River, a tributary to Newark Bay, for inclusion in the Superfund program. We no longer manufacture gas.

Site Remediation—The Federal Comprehensive Environmental Response, Compensation and Liability Act of 1980 (CERCLA) and the New Jersey Spill Compensation and Control Act (Spill Act) require the remediation of discharged hazardous substances and authorize the EPA, the NJDEP and private parties to commence lawsuits to compel clean-ups or 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.

Natural Resource Damages—CERCLA and the Spill Act authorize the assessment of damages against persons who have discharged a hazardous substance, causing an injury to natural resources. Pursuant to the Spill Act, the NJDEP requires persons conducting remediation to address injuries to natural resources through restoration or damages. The NJDEP adopted regulations concerning site investigation and remediation that require an ecological evaluation of potential damages to natural resources in connection with an environmental investigation of contaminated sites.

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 United States Department of Energy (DOE) has set the nuclear waste fee rate at 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 formed the Atlantic Compact, which gives New Jersey nuclear generators continued access to the Barnwell waste disposal facility which is owned by South Carolina. We believe that the Atlantic Compact 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 Barnwell site 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,
2021

Office

Effective Date
First Elected to
Present Position

Ralph Izzo

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

April 2007 to present

COB and CEO - PSE&G

April 2007 to present

COB and CEO - PSEG Power

April 2007 to present

COB and CEO - Energy Holdings

April 2007 to present

COB and CEO - Services

January 2010 to present

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

Ralph A. LaRossa

COB - PSEG Long Island LLC

December 2020 to present

Chief Operating Officer (COO) - PSEG

January 2020 to present

President and COO - PSEG Power

October 2017 to present

President and COO - PSE&G

October 2006 to October 2017

COB - PSEG Long Island LLC

October 2013 to October 2017

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

Vice President (VP) - Delivery, Projects and Construction - PSE&G

December 2010 to July 2014

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

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

VP-Finance, Holdings and Corporate Strategy and Planning - Services

October 2015 to November 2017

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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.

In August 2021, PSEG entered into two agreements to sell PSEG Power’s 6,750 MW fossil generating portfolio to newly formed subsidiaries of ArcLight Energy Partners Fund VII, L.P., a fund controlled by ArcLight Capital Partners, LLC. In February 2022, we completed the sale of this fossil generating portfolio. As a result, risks described in this Item 1A and otherwise in this document that relate solely to this 6,750 MW fossil generating portfolio, except for those related to certain assets and liabilities excluded from the sale transactions, primarily for obligations under environmental regulations, including possible remediation obligations under the New Jersey Industrial Site Recovery Act and the Connecticut Transfer Act, are no longer relevant to our business.

GENERAL OPERATIONAL AND FINANCIAL RISKS

Inability to successfully develop, obtain regulatory approval for, or construct T&D, and solar and wind 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 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;

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

•complete supporting information technology 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

•recover the related costs through rates.

Any delays, cost escalations or otherwise unsuccessful construction and development could materially affect our financial position, results of operations and cash flows.

In addition, the successful operation of new solar or wind or upgraded generation 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. Further, negative public and political views on natural gas could result in diminishing political support for utility investments in gas infrastructure.

Any of these risks could cause our return on these investments to be lower than expected or they could cause these facilities to operate below intended targets, which could adversely impact our financial condition and results of operations through lost revenue and/or increased expenses.

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.

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 margin variances against changes in customer usage of gas and electricity, customer demand for our 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, installation of

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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 reduce demand for electricity and gas we deliver. Fluctuations in weather can also affect demand for our services. For example, milder than normal weather can reduce demand for electricity and gas distribution services. 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 and other natural disasters can stress systems, disrupt operation of our facilities and cause service outages, production delays 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 GHG emissions as a financial risk, our ability to access capital markets could be negatively affected or cause us to receive less than ideal terms and conditions.

Climate change-related political pressure and policy goals, including but not limited to those related to energy efficient targets, solar targets, encouragement of electrification through EV adoption, home heating, 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, and our suppliers. 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 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, and punitive damages, including but not limited to, for liabilities for personal injuries and property damage 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.

We may be adversely affected by asset and equipment failures, critical operating technology or business system failures, accidents, natural disasters, severe weather events, acts of war or terrorism, sabotage, cyberattack, or other incidents, including pandemics such as the ongoing 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, accidents, natural disasters, severe weather events, acts of war or terrorism, sabotage, cyberattack or other incidents, which could result in damage to or destruction of our facilities or damage to persons or property and to 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 are also exposed to the risk of pandemics, such as the ongoing coronavirus pandemic, which could result in service disruptions and delay or otherwise impair our ability to timely provide service to our customers or complete our investment projects.

These events could result in increased political, economic, financial and insurance market instability 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, climate change will exacerbate 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. Such issues experienced at our facilities, 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

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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 70% and 83% of the total assets of PSEG and PSE&G, respectively, as of December 31, 2021. 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, 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 the costs of such financing 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;

•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, to extend or refinance maturing debt or for 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.

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.

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

Cybersecurity threats to the energy market infrastructure are increasing in sophistication, magnitude and frequency, particularly since COVID-19 and the resulting shift to virtual operations began. 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 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 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, employees, shareholders, customers and vendors on our systems and conduct power marketing and hedging activities. In addition, the operation of our business is dependent upon the information technology systems of third parties, including our vendors, regulators, RTOs and ISOs, among others. Our and third-party information technology 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. A cybersecurity attack may also leverage such information technology to cause disruptions at a third party. Cybersecurity impacts to our operations include:

•disruption of the operation of our assets, 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,

•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, and malware attacks. While there has been no material impact on our business or operations from these attacks to date, 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 for 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 or unforeseen threat sources could require changes in current measures taken by us and our business operations, which could result in increased costs and 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 1. Business—Regulatory Issues—Cybersecurity.

Our financial condition and results of operations could be adversely affected by the ongoing coronavirus pandemic.

In response to the ongoing global coronavirus pandemic, we have implemented a comprehensive set of actions to help our customers, communities and employees, and will continue to closely monitor developments and adjust as needed to ensure reliable service while protecting the safety and health of our workforce and the communities we serve.

PSE&G, PSEG Power and PSEG LI are providing essential services during this national emergency related to the coronavirus pandemic. The pandemic’s potential impact will depend on a number of factors outside of our control, including the duration and severity of the outbreak as well as third-party actions, including governmental requirements, taken to contain its spread and mitigate its public health effects. We currently cannot estimate the potential impact the ongoing coronavirus pandemic may have on our business, results of operations, financial condition, liquidity and cash flows. However a prolonged outbreak and associated government and regulatory responses, including the long-term impact they may have on the economy, which could extend beyond the duration of the pandemic, could affect, among other things:

•the timing of our planned capital programs, including the ability to obtain necessary permits and approvals for our capital programs;

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•PSE&G’s residential and C&I customer payment patterns, in part as residential customer non-safety related service disconnections for non-payment have been temporarily suspended, resulting in adverse impacts to accounts receivable and bad debt expense;

•the recovery of incremental costs incurred related to the pandemic, including higher bad debts;

•the availability of capital markets and credit from banks and other financial institutions to fund our operations and capital programs and the cost of borrowing and available terms;

•the availability and productivity of skilled workers and contractors to operate our facilities;

•the ability of our counterparties to meet their contractual obligations to us;

•the potential for assessment of impairment of our long-lived assets;

•financial market performance that adversely impacts asset values in our pension and Nuclear Decommissioning Trust (NDT) funds, adversely impacts Net Income and potentially increases related funding requirements; and

•the availability of materials and supplies due to supply chain interruptions.

Any failure or breach of these systems would have a material impact on our business and results of operations.

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

Certain events such as an aging workforce without adequate workforce plans and replacements, a lack of skill set to complement evolving business needs, a culture that does not foster inclusion, a labor strike and unavailability of resources due to health impacts or protocol mandates related to the COVID-19 pandemic may lead to operating challenges 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, and productivity and safety costs. Specialized knowledge is required of the technical and support employees for our carbon-free infrastructure investments and generation and T&D operations. There is competition and a tightening market for skilled employees. Failure to hire and adequately train and retain employees, including the transfer of significant historical knowledge and expertise to new employees, or future availability and cost of contract labor 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.

Inflation has recently increased across the economy and is impacting portions of our business. 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 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 may adversely affect our business.

PSEG’s and PSE&G’s fixed income debt instruments contain events of default customary for financings of their type, including cross accelerations to other debt of that entity and, in the case of PSEG’s, PSE&G’s and PSEG Power’s bank credit agreements, certain change of control events and certain limitations on the incurrence of liens. PSEG Power’s bank credit agreements also contain limitations on the incurrence of subsidiary debt. 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 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 Nuclear Decommissioning Trust (NDT) Fund and defined benefit plan trust funds. 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 our NDT Fund could increase PSEG Power’s funding requirements to decommission its nuclear plants. A decline in the market value of the defined benefit plan trust funds could increase our pension plan funding requirements. The market value of our trusts could be negatively impacted by decreases in the rate of 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. Increased costs could also lead to additional funding requirements for our

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decommissioning trust. Failure to manage adequately our investments in our NDT Fund and defined benefit plan trusts 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.

RISKS RELATED TO OUR GENERATION BUSINESS

Failure to complete, or delays in completing, our proposed investment in the Ocean Wind project could adversely impact our businesses and prospects.

In December 2020, PSEG entered into a definitive agreement with Ørsted North America to acquire a 25% equity interest in Ørsted’s Ocean Wind project. On March 31, 2021, the BPU approved PSEG’s investment in Ocean Wind and the acquisition was completed in April 2021.

Our ability to realize the anticipated strategic and financial benefits of these projects is subject to a number of risks, challenges and uncertainties, including, among others:

•the risk that we or Ørsted may determine not to proceed with the project at certain milestones in the development of the project, in accordance with the terms of the transaction documents;

•the fact that, subject to certain investment decision milestones, we will be obligated to fund our proportionate share of future capital expenditures in respect of the project, and such future capital expenditures may be greater than expected as a result of, among other things, potential timing delays, cost overruns, labor disputes or unanticipated liabilities;

•the risk that there may be changes to the tax laws, rules and interpretations applicable to a project, including the risk of any reduction, elimination or expiration of government incentives for wind energy or otherwise that may adversely affect such project’s ability to realize certain anticipated tax benefits and, by extension, our ability to realize a satisfactory return on our investment in the project, including in our capacity as a tax equity investor;

•certain limitations on our ability to influence and control strategic decisions related to the project given our status as a minority investor, and the possibility that we and Ørsted may have different views and priorities regarding the development, construction and operation of the project, as well as other risks and uncertainties inherent in joint venture arrangements;

•risks inherent in entering into a new line of business, offshore wind, in which we have not historically operated, and which may expose us to business and operational risks and liabilities that are different from those we have experienced historically and that may be more difficult to manage given our limited operational experience and resources in this area;

•the risk that we may fail to obtain or maintain, on acceptable terms or at all, any required licenses, permits and other regulatory or third party approvals, or may encounter other environmental or regulatory compliance issues, in connection with the project; and

•the risk of catastrophic events, including damage to project equipment, caused by earthquakes, tornadoes, hurricanes, floods, fires, severe weather, explosions and other natural disasters.

If any such risks or other anticipated or unanticipated liabilities were to materialize, the anticipated benefits of a project may not be fully realized, if at all, and the future performance of the project and our investment therein, as well as our financial condition and results of operations, may be materially and adversely impacted.

Further, as the offshore wind market matures, it may attract more capital and competition and potentially lower the rate of return on any offshore wind projects we are involved in.

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

In the markets where we operate, natural gas prices have a major impact on the price that generators receive for their output. Over the past several years, wholesale prices for natural gas have remained well below the peak levels experienced in 2008, in part due to increased shale gas production as extraction technology has improved. Lower gas prices have resulted in lower electricity prices, which have reduced our margins as nuclear generation costs have not declined similarly. Recently, the natural gas market, and therefore energy markets have become more volatile, which could impact our results of operations and cash flows.

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

We obtain substantially all of our physical natural gas and 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

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transportation agreements, balancing agreements, storage services and other contracts to ensure that the natural gas and nuclear fuel are 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 natural gas and 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 natural gas and 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 natural gas and nuclear fuel by, our power plants including the following:

•transportation may be unavailable if pipeline infrastructure is damaged or disabled;

•pipeline tariff changes may adversely affect our ability to, or cost to, deliver such fuels;

•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. storage) 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;

•legislative or regulatory actions or requirements, including those related to pipeline integrity inspections, may increase the cost of such fuels;

•fuel supplies diverted to residential heating may limit the availability of such fuels for our power plants; 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 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. Certain of our other generation facilities also require fuel or other services that may only be available from one or a limited number of suppliers. The availability and price of this fuel may vary due to supplier financial or operational disruptions, transportation disruptions, force majeure and other factors, including market conditions. At times, such fuel may not be available at any price, or we may not be able to transport it to our facilities on a timely basis. In this case, we may not be able to run those facilities even if it would be profitable. If we had sold forward the power from such a facility, we could be required to supply or purchase power from alternate sources, perhaps at a loss. 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. While our generation runs on a mix of fuels, primarily natural gas and nuclear fuel, an increase in the cost of any particular fuel ultimately used could impact our results of operations.

Operation of our generating stations are subject to market risks that are beyond our control.

Generation output will either be used to satisfy wholesale contract requirements or other bilateral contracts or be sold into competitive power markets. Participants in the competitive power markets are not guaranteed any specified rate of return on their capital investments. Generation revenues and results of operations are dependent upon prevailing market prices for energy, capacity, ancillary services and fuel supply in the markets served. Changes in prevailing market prices could have a material adverse effect on our financial condition and results of operations.

Factors that may cause market price fluctuations include:

•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;

•power transmission or fuel transportation capacity constraints or inefficiencies;

•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;

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•economic and political conditions that could negatively impact the demand for power;

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

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

•federal and state regulations and actions of the ISOs; 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.

Our generation business frequently 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, customer migration 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.

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

The power generation business has seen a substantial change in the technologies used to produce power. Newer generation facilities are often more efficient than aging facilities, which may put some of these older facilities at a competitive disadvantage to the extent newer facilities are able to consume the same or less fuel to achieve a higher level of generation output. 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 DSM and energy efficiency programs can impact demand requirements for some of our markets at certain times during the year. The continued development of subsidized, competing power generation technologies and significant development of DSM and energy efficiency 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. Technological advances driven by federal laws mandating new levels of energy 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, may reduce the cost of alternative methods of producing electricity 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, such as Massachusetts and California, 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.

Some or all of these factors could result in a lack of growth or decline in customer demand for electricity or number 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 generation output and purchase of 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

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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 may not be able to meet its commitments under forward sale obligations at a reasonable cost or at all.

A substantial portion of PSEG Power’s base load generation output has been sold forward under fixed price power sales contracts and PSEG Power also sells forward the output from its intermediate and peaking facilities when it deems it commercially advantageous to do so. Our forward sales of energy and capacity assume sustained, acceptable levels of operating performance. This is especially important at our lower-cost facilities. 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, information technology, processes or management effectiveness;

•disruptions in the transmission of electricity;

•labor disputes or work stoppages;

•fuel supply interruptions;

•transportation constraints;

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

•operator error, acts of war or terrorist attacks (including cybersecurity breaches) or catastrophic events such as fires, earthquakes, explosions, floods, severe storms 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 is generally required to deliver power to the buyer even in the event of a plant outage, fuel supply disruption or a reduction in the available capacity of the unit. To the extent that PSEG Power does not have sufficient lower cost capacity to meet its commitments under its forward sale obligations, PSEG Power would be required to pay the difference between the market price at the delivery point and the contract price. 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, 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.

Certain of our generation facilities rely on transmission facilities that we do not own or control and that may be subject to transmission constraints. Transmission facility owners’ inability to maintain adequate transmission capacity could restrict our ability to deliver wholesale electric power to our customers and we may either incur additional costs or forgo revenues. Conversely, improvements to certain transmission systems could also reduce revenues.

We depend on transmission facilities owned and operated by others to deliver the wholesale power we sell from our generation facilities. If transmission is disrupted or if the transmission capacity infrastructure is inadequate, our ability to sell and deliver wholesale power may be adversely impacted. If a region’s power transmission infrastructure is inadequate, our recovery of wholesale costs and profits may be limited. If restrictive transmission price regulation is imposed, the transmission companies may not have sufficient incentive to invest in transmission infrastructure. We also cannot predict whether transmission facilities will invest in specific markets to accommodate competitive access to those markets.

In addition, in certain of the markets in which we operate, energy transmission congestion may occur and we may be deemed responsible for congestion costs if we schedule delivery of power between congestion zones during times when congestion occurs between the zones. If we were liable for such congestion costs, our financial results could be adversely affected.

Conversely, a portion of our generation is located in load pockets. Investment in transmission systems to reduce or eliminate these load pockets could negatively impact the value or profitability of our existing generation facilities in these areas.

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

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and could result in fines, penalties or sanctions. The retail rates for electric and gas distribution services are established in a base rate proceeding and remain in effect until a new base rate proceeding is filed and concluded. 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. 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, 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.

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 15. 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 programs may not be fully approved by regulators, which could result in lower than desired service levels to customers, 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 energy efficiency 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 review in the FERC-approved PJM transmission expansion process while distribution and clean energy projects are subject to approval by the BPU. We cannot be certain that any proposed project will be approved as requested or at all. If the 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. If these programs are not approved, that could also adversely affect our service levels for customers. Further, the BPU could take positions to exclude or limit utility participation in certain areas, such as renewable generation, energy efficiency, EV infrastructure and energy storage, 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. Over the past several years, several companies have negotiated settlements that have resulted in reduced ROEs.

In October 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 reduces PSE&G’s base ROE from 11.18% to 9.9% and makes changes to recovery of certain costs. The agreement provides that the settling parties will not seek changes to our transmission formula rate for three years. We have implemented the terms of the agreement and PJM issued refunds to wholesale customers in January 2022.

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 could reduce PSE&G’s annual Net Income and annual cash inflows by approximately $30 million-$40 million.

Transmission Policy—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

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incumbents for construction responsibility, including immediately needed reliability projects, upgrades to existing transmission facilities, projects cost-allocated to a single transmission zone, and projects being built on existing rights-of-way, 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.

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 and are subject to penalties for non-compliance with applicable NERC standards. 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.

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 evaluated differently in the future, could have a material adverse effect on our business, financial condition and results of operations.

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.

Our New Jersey nuclear plants may not be awarded ZECs in future periods, or the current or subsequent ZEC program periods could be materially adversely modified through legal proceedings, either of which could result in the retirement of all of these nuclear plants.

As further described in Item 7. MD&A—Executive Overview of 2021 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. The ZEC payment may be adjusted by the BPU under certain conditions. For instance, the New Jersey Rate Counsel, in written comments filed with the BPU, has advocated for the BPU to offset market benefits resulting from New Jersey’s rejoining the RGGI from the ZEC payment. PSEG intends to vigorously defend against these arguments. Due to its preliminary nature, PSEG cannot predict the outcome of this matter.

In May 2021, the New Jersey Rate Counsel filed an appeal with the New Jersey Appellate Division of the BPU’s April 2021 decision. PSEG cannot predict the outcome of these matters.

In the event that (i) the ZEC program is overturned or is otherwise materially adversely modified through legal process; or (ii) any of the Salem 1, Salem 2 and Hope Creek plants is not sufficiently valued for its environmental, fuel diversity or resilience attributes in future periods and does not otherwise experience a material financial change that would remove the need for such attributes to be sufficiently valued, PSEG Power will take all necessary steps to cease to operate all of these plants. Alternatively, even with sufficient valuation of these attributes, if the financial condition of the plants is materially adversely impacted by changes in commodity prices, FERC’s changes to the capacity market construct (absent sufficient capacity revenues provided under a program approved by the BPU in accordance with a FERC-authorized capacity mechanism), 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 Clean Water Act (CWA) and related state regulations, or other factors, PSEG Power will take all necessary steps to cease to operate all of these plants. 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 each of PJM, ISO-NE

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and NYISO. 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 and ISO-NE’s FCM rules continue to evolve, most recently in response to efforts to integrate public policy initiatives into the wholesale markets. For a discussion of recent changes in energy regulatory policies that may affect our business and results of operations, see Item 7. MD&A—Executive Overview of 2021 and Future Outlook.

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.

To the extent that additions to the transmission system relieve or reduce congestion in eastern PJM where most of our plants are located, PSEG Power’s capacity and energy revenues could be adversely affected. Moreover, through changes encouraged by FERC to transmission planning processes, or through RTO/ISO initiatives to change their planning processes, more transmission may ultimately be built to facilitate renewable generation or support other public policy initiatives. Any such addition to the transmission system could have a material adverse impact on our financial condition and results of operations.

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

Over half of our total generation output each year is provided by our nuclear fleet. For this reason, 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 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 happened, identifying and correcting the causes may require significant time and expense. Any significant outages could result in reduced earnings as we would have less electric output to sell.

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

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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.

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. With the change in administration following the 2020 presidential election, there have been various recent 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 PSEG Power and 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 will retain ownership of certain assets and liabilities excluded from the sale of its fossil generation business, primarily related to obligations under environmental regulations, including possible remediation obligations under the New Jersey Industrial Site Recovery Act and the Connecticut Transfer Act. Fulfilling the requirements under these regulations will span multiple years and may require sampling of environmental media to understand the extent of any required remediation. The amounts for any such environmental remediation are not estimable, but may be material.

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 GHG emissions and remediation of environmental contamination, see Item 1. Environmental Matters and Item 8. Note 15. Commitments and Contingent Liabilities.

We may not receive necessary licenses and permits 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 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.

A prolonged coronavirus pandemic, further economic stimulus, or future federal and state tax legislation 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 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 15. 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, 2021, PSE&G’s electric T&D system included approximately 25,000 circuit miles, and 862,000 poles, of which 64% are jointly-owned. In addition, PSE&G owns and operates 56 switching stations with an aggregate installed capacity of 39,353 megavolt-amperes (MVA) and 235 substations with an aggregate installed capacity of 9,285 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, 2021, 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 58 natural gas metering and regulating stations, of which 22 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 2.8 million therms in the aggregate.

Solar

As of December 31, 2021, PSE&G owned 158 MW dc of installed PV solar capacity throughout New Jersey.

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PSEG Power

Generation Facilities

As of December 31, 2021, PSEG Power’s share of installed fossil and nuclear generating capacity is shown in the following

table:



Name	Location	Total Capacity (MW)	% Owned	Owned Capacity (MW)	Principal Fuels Used
Nuclear:
Hope Creek	NJ	1,185	100%	1,185	Nuclear
Salem 1 & 2	NJ	2,285	57%	1,311	Nuclear
Peach Bottom 2 & 3 (A)	PA	2,549	50%	1,275	Nuclear
Total Nuclear		6,019		3,771
Steam:
New Haven Harbor	CT	448	100%	448	Oil/Gas
Total Steam		448		448
Combined Cycle:
Keys	MD	761	100%	761	Gas
Bergen	NJ	1,245	100%	1,245	Gas/Oil
Linden	NJ	1,300	100%	1,300	Gas/Oil
Sewaren 7	NJ	538	100%	538	Gas/Oil
Bridgeport Harbor 5	CT	484	100%	484	Gas
Bethlehem	NY	816	100%	816	Gas
Kalaeloa	HI	208	50%	104	Oil
Total Combined Cycle		5,352		5,248
Combustion Turbine:
Essex	NJ	81	100%	81	Gas/Oil
Kearny	NJ	456	100%	456	Gas/Oil
Burlington	NJ	168	100%	168	Gas/Oil
Linden	NJ	336	100%	336	Gas/Oil
New Haven Harbor	CT	130	100%	130	Gas/Oil

Total Combustion Turbine		1,171		1,171
Total PSEG Power Plants		12,990		10,638

(A)Operated by Exelon Generation.

Effective May 31, 2021, PSEG Power retired its Bridgeport Harbor 3 coal plant.

In June 2021, PSEG Power completed the sale of its 467 MW dc of PV solar generation facilities located in various states. In February 2022, PSEG Power’s fossil generating plants in New Jersey, Connecticut, Maryland and Pennsylvania were sold. See Item 8. Note 4. Early Plant Retirements/Asset Dispositions and Impairments for additional information.

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 15. Commitments and Contingent Liabilities.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

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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 18, 2022, there were 52,145 registered holders.

The following graph shows a comparison of the five-year cumulative return assuming $100 invested on December 31, 2016 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.



	2016		2017		2018		2019		2020		2021
PSEG	$	100.00	$	121.77	$	127.46	$	149.23	$	152.79	$	180.80
S&P 500	$	100.00	$	121.82	$	116.47	$	153.13	$	181.29	$	233.28
DJ Utilities	$	100.00	$	113.35	$	115.60	$	147.16	$	149.63	$	175.76
S&P Utilities	$	100.00	$	112.10	$	116.71	$	147.46	$	148.24	$	174.43

On February 15, 2022, our Board of Directors approved a $0.54 per share common stock dividend for the first quarter of 2022. This reflects an indicative annual dividend rate of $2.16 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.

In late September 2021, PSEG announced a $500 million share repurchase program to be implemented upon the close of the sale of the fossil generation assets. In November 2021, the Board of Directors authorized senior management to implement the share repurchase program at such time as senior management deemed appropriate in its discretion, whether before or after the closing of the fossil sale. In December 2021, under this authorization PSEG entered into an open market share repurchase plan

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for $250 million of our common shares that complies with Rule 10b5-1 of the Securities Exchange Act of 1934, as amended. There were no common share repurchases during the fourth quarter of 2021. During January and through February 16, 2022, we purchased the full $250 million of common shares under the open market share repurchase plan.

The following table indicates the securities authorized for issuance under equity compensation plans as of December 31, 2021:



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	—	$	—	10,121,383
Equity Compensation Plans Not Approved by Security Holders	—	—		—
Total	—	$	—	10,121,383

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 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. The Amended and Restated 2004 LTIP, and the 2007 Equity Compensation Plan for Outside Directors were closed as of April 20, 2021 and all available shares under these plans as of that date or that will become available in the future are cancelled. For additional discussion of specific plans concerning equity-based compensation, see Item 8. Note 20. 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]

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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), our principal direct wholly owned subsidiaries, which are:

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

•PSEG Power—which is a multi-regional energy supply company that integrates the operations of its merchant nuclear and fossil generating assets with its fuel supply functions through competitive energy sales in well-developed energy markets primarily in the Northeast and Mid-Atlantic United States through its principal direct wholly owned subsidiaries. PSEG Power’s subsidiaries are subject to regulation by FERC, the Nuclear Regulatory Commission (NRC), the Environmental Protection Agency (EPA) and the states in which they operate. PSEG Power is no longer a Securities and Exchange Commission (SEC) registrant; however, it continues to be consolidated and reported in PSEG’s financial statements as a wholly owned subsidiary and operating segment.

In August 2021, PSEG entered into two agreements to sell PSEG Power’s 6,750 megawatts (MW) fossil generating portfolio to newly formed subsidiaries of ArcLight Energy Partners Fund VII, L.P., a fund controlled by ArcLight Capital Partners, LLC. In February 2022, we completed the sale of this fossil generating portfolio. As a result, disclosures in this Item 7 and elsewhere in this document that relate solely to this 6,750 MW fossil generating portfolio, except for those related to certain assets and liabilities excluded from the sale transactions, primarily for obligations under environmental regulations, including possible remediation obligations under the New Jersey Industrial Site Recovery Act and the Connecticut Transfer Act, are no longer relevant to our business.

PSEG’s other direct wholly owned subsidiaries are: PSEG Energy Holdings L.L.C. (Energy Holdings), which holds our investments in offshore wind ventures and legacy portfolio of lease investments; 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); and PSEG Services Corporation (Services), which provides certain management, administrative and general services to PSEG and its subsidiaries at cost.

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 2021 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.

For a discussion of 2020 items and year-over-year comparisons of changes in our financial condition and results of operations as of and for the years ended December 31, 2020 and December 31, 2019, 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, 2020 (2020 Annual Report) as filed with the SEC on February 26, 2021.

EXECUTIVE OVERVIEW OF 2021 AND FUTURE OUTLOOK

We are progressing on our strategy to become a predominantly regulated electric and gas utility and a contracted carbon-free energy infrastructure company. We are focused on meeting customer expectations and being well aligned with public policy objectives by investing to modernize our energy infrastructure, improve reliability, increase energy efficiency and deliver cleaner energy. Our business plan focuses on achieving growth while controlling costs and managing the risks associated with regulatory and policy changes and fluctuating commodity prices. In furtherance of these goals, over the past few years, our investments have altered our business mix to reflect a higher percentage of earnings contribution by PSE&G, which improves

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the sustainability and predictability of our earnings and cash flows. In June 2021, we completed the sale of PSEG Power’s solar portfolio and in August 2021 we entered into two agreements to sell PSEG Power’s 6,750 MW of fossil generation located in New Jersey, Connecticut, New York and Maryland. In February 2022, we completed the sale of this fossil generation portfolio, which represented an important milestone in our strategy and has further altered our business mix, resulting in an even higher percentage of earnings contribution by PSE&G going forward and provides more financial flexibility. See Item 8. Note 4. Early Plant Retirements/Asset Dispositions and Impairments for additional information.

PSE&G, PSEG Power and PSEG LI are providing essential services during the coronavirus (COVID-19) pandemic. We have implemented a comprehensive set of enhanced safety actions to help protect our employees, customers and communities, and we will continue to closely monitor developments and adjust as needed to ensure that we provide reliable service while protecting the safety and health of our workforce and the communities we serve. We continue to be guided by the recommendations of health authorities at the federal, state and local levels.

The COVID-19 pandemic and associated government actions and economic effects continue to impact our businesses. We have incurred additional expenses to protect our employees and customers, and PSE&G is experiencing significantly higher customer bad debts and lower cash collections, as discussed below. The potential future impact of the pandemic and the associated economic impacts, which could extend beyond the duration of the pandemic, will depend on a number of factors outside of our control. These include the duration and severity of the outbreaks as well as third-party actions taken to contain their spread and mitigate their public health effects, and governmental or regulatory actions regarding customer collections, potential limitations on rate increases, recovery of incremental costs, and other matters. While we currently cannot estimate the potential impact to our results of operations, financial condition and cash flows, this MD&A includes a discussion of potential effects of a prolonged outbreak.

PSE&G

At PSE&G, our focus is on enhancing reliability and resiliency of our T&D system, meeting customer expectations and supporting public policy objectives by investing capital in T&D infrastructure and clean energy programs. For the years 2021-2025, PSE&G’s capital investment program is estimated to be in a range of $14 billion to $16 billion, resulting in an expected compound annual growth in rate base of 6.5% to 8%. The low end of the range assumes an extension of our Gas System Modernization Program (GSMP) and Clean Energy Future (CEF)-Energy Efficiency (EE) program at their average annual investment levels, as these programs are expected to continue at least at those current rates beyond their currently approved timeframe of 2023. The upper end of the range is driven by certain unapproved investment programs, including an Infrastructure Advancement Program (IAP) which we filed in November 2021. The IAP is a proposed $848 million investment program made over four years to improve the reliability of the “last mile” of our electric distribution system, address aging substations and gas metering and regulating stations and invest in electric vehicle charging infrastructure at our facilities to support the electrification of our fleet over the coming years. The upper end of the range also includes an extension of our Energy Strong program, which otherwise concludes in 2023, as well as the remaining portion of our CEF proposal (portion of Electric Vehicle (EV) and Energy Storage (ES) programs) and a potentially higher amount of investment for GSMP and CEF-EE beyond current levels. During 2022, we expect to file for extensions of our GSMP and CEF-EE program, which we expect will conclude in the first half of 2023.

In September 2020, PSE&G reached a settlement with parties in the CEF-EE proceeding, which the BPU approved. The settlement commits $1 billion over a three-year period, with the majority of the investment occurring over a five-year period. Costs will be recovered through annual rate-making, with returns aligned with our most recent base rate case and a ten-year amortization period.

The approval also included a Conservation Incentive Program (CIP), a mechanism that provides for recovery of lost electric and gas variable margin revenues relative to a baseline of the test year (July 2017 to June 2018) set in in our last base rate case. The deferral period for this mechanism became effective in June 2021 for electric and October 2021 for gas. PSE&G suspended its gas Weather Normalization Charge (WNC) when the gas CIP began.

In January 2021, the BPU approved a settlement with PSE&G and other parties in the CEF-Energy Cloud (EC) proceeding. The capital cost of the program, which is driven by the implementation of advanced metering infrastructure (AMI), is estimated to be $707 million, invested over the next four years.

Also in January 2021, the BPU approved a settlement with PSE&G and other parties in the CEF-EV proceeding for a majority of the components of the program. The approved investment under the program is for approximately $166 million, 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 fast charging. A remaining component of our program related to medium and heavy duty charging infrastructure was the subject of a stakeholder process at the BPU in 2021. We currently anticipate that this effort will conclude with PSE&G submitting a filing in mid-year 2022 targeting infrastructure investments for the medium and heavy duty EV market.

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All of the capital costs and expenses of the CEF-EC and CEF-EV programs are expected to be recovered in PSE&G’s next base rate case, expected to be filed with the BPU by the end of 2023. From the start of the program until the commencement of new base rates, the return on and of the capital portion of each of these programs, as well as expenses incurred to implement the CEF-EV program and operating costs and stranded costs associated with the retirement of existing meters under the CEF-EC program, will be included for recovery as part of our next rate case expected to be concluded in the second half of 2024. Our CEF-ES program is being held in abeyance pending future policy guidance from the BPU.

We also continue to invest in transmission infrastructure in order to (i) maintain and enhance system integrity and grid reliability, (ii) ensure system resilience in the face of continued extreme weather conditions and cyber and physical security threats, (iii) address an aging transmission infrastructure, (iv) leverage technology to improve the operation of the system, (v) reduce transmission constraints, (vi) meet changing customer usage patterns and the demand for 24/7 electricity, and (vii) satisfy state public policy goals, including aggressive decarbonization agendas. As part of a solicitation by the BPU, we also proposed two transmission projects to support the development of offshore wind which are being evaluated by the BPU and PJM Interconnection, L.L.C. (PJM), with project awards expected in late 2022. As discussed further below, in October 2021, FERC approved PSE&G’s settlement with the BPU and the New Jersey Division of Rate Counsel (New Jersey Rate Counsel) regarding several amendments to our transmission formula rate, including the reduction of its base transmission return on equity (ROE) from 11.18% to 9.9%. Under current FERC rules, we continue to earn a 50 basis point adder to that base ROE for our membership in PJM.

The ongoing coronavirus pandemic and associated impacts could have several negative consequences, including potential delays of our regulatory agencies’ review and approval of proposed programs or rate recovery.

The coronavirus has also impacted PSE&G’s sales, with a reduction in demand from its commercial and industrial (C&I) customers, largely offset by increases in residential sales volumes. As a result, there has been no substantive net margin impact and changes are now largely addressed through the CIP mechanism that became effective in 2021. The most substantive impact of the pandemic on our financial position has been adverse changes to residential and C&I payment patterns. The State of New Jersey issued an Executive Order in March 2020 that included a moratorium on non-safety related service disconnections for non-payment. On June 30, 2021, the moratorium imposed by the State of New Jersey ended but the State had established a “grace period” prohibiting disconnections for residential customers through December 31, 2021. On January 22, 2022, the State extended the grace period to March 15, 2022. Consequently, collections and shut-offs will not be in full effect until mid-March 2022. During the moratorium, PSE&G has experienced a significant decrease in cash inflow and higher Accounts Receivable aging and an associated increase in bad debt expense, which we expect will continue through the grace period and winter moratorium and take the next several years to fully return to normal levels. Since the start of the pandemic, PSE&G’s allowance for credit losses has increased by approximately $265 million. PSE&G’s electric distribution bad debt expense is recoverable through its Societal Benefits Clause (SBC) mechanism. PSE&G has deferred its incremental gas distribution bad debt expense as a result of COVID-19 as a Regulatory Asset and will seek recovery of that cost, as well as other net incremental COVID-19 costs, in its next base rate case. Collection efforts with C&I customers recommenced in the fourth quarter of 2021 and residential customer collection efforts will recommence in March 2022, with a focus on enrolling customers in payment support programs. Any further moratoriums on shut-offs or collection processes could have a material effect on our cash flows, and, to the extent not fully recovered through a rate-making process, on our financial results and condition.

In July 2020, the BPU authorized regulated utilities in New Jersey, including PSE&G, to create a COVID-19-related Regulatory Asset by deferring on their books and records prudently incurred incremental costs related to COVID-19 beginning on March 9, 2020 through September 30, 2021 for recovery in a future rate case. In September 2021, the BPU extended the authorization to defer such costs through December 31, 2022. 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. As of December 31, 2021, PSE&G has recorded a Regulatory Asset related to COVID-19 to defer incremental costs of $116 million, which PSEG believes are recoverable under the BPU Order.

PSEG Power

In July 2020, we announced that we were exploring strategic alternatives for PSEG Power’s non-nuclear generating fleet with the intention of accelerating the transformation of our business into a predominantly regulated electric and gas utility, with a significantly contracted generation business. See Item 8. Note 4. Early Plant Retirements/Asset Dispositions and Impairments for additional information.

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.

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February 2022, PSEG completed the sale of this fossil generating portfolio. These transformative transactions are expected to reduce overall business risk and earnings volatility, improve PSEG’s financial flexibility and are consistent with PSEG’s climate strategy and sustainability efforts, which are to focus on clean energy investments, methane reduction, and the transition to carbon-free generation. See Item 8. Note 4. Early Plant Retirements/Asset Dispositions and Impairments for additional information.

We have sought to achieve operational excellence and manage costs in order to optimize cash flow generation from our fleet in light of low wholesale power and gas prices, environmental considerations and competitive market forces that reward efficiency and reliability. During 2021, our natural gas and nuclear units generated 22.5 and 31.2 terawatt hours and operated at a capacity factor of 49.1% and 91.9%, respectively. PSEG Power’s hedging practices help to manage some of the volatility of the merchant power business. More than 90% of PSEG Power’s expected gross margin in 2022 from the expected remaining generation assets after the sale of the fossil generation portfolio relates to hedging of our energy margin, our expected revenues from the capacity market mechanisms, Zero Emission Certificate (ZEC) revenues and, certain gas operations and ancillary service payments such as reactive power. While this limits our exposure to decreasing prices, our ability to realize benefits from rising market prices is also limited. As a result of significantly rising energy prices, as experienced during the second half of 2021, PSEG Power experienced a substantial increase in net cash collateral postings related to hedge positions that are out-of-the-money. As of December 31, 2021, net cash collateral postings were $844 million.

As discussed further below under “Wholesale Power Market Design,” in July 2021, PJM submitted to FERC a proposal to replace the current Minimum Offer Price Rule (MOPR), which applies to both new and existing resources that receive out-of-market payments, with new provisions that accommodate state public policy programs that do not attempt to set the price of capacity. Under the PJM proposal, PSEG Power’s New Jersey nuclear plants that receive ZEC payments would not be subject to the MOPR. PJM’s proposal requested that FERC approve the new provisions for the next Reliability Pricing Model (RPM) auction. In September 2021, FERC issued a notice that it was not able to act on PJM’s proposed changes to the MOPR because of a split among the Commissioners on the lawfulness of the proposal. Therefore, PJM’s rules became automatically effective as of September 29, 2021 and will apply to the next base residual auction. In February, FERC approved PJM’s filing requesting that the auction be held in June 2022.

PSEG LI

Following the effects of Tropical Storm Isaias, the New York Attorney General (AG) initiated an inquiry into PSEG LI’s preparation and response to the storm. In addition, the Department of Public Service (DPS) within the New York State Public Service Commission launched an investigation of the State’s electric service providers’, including PSEG LI’s, preparation and response to the storm. The DPS issued an interim storm investigation report finding that PSEG LI violated its Emergency Response Plan and DPS Regulations, and recommended that LIPA consider taking various actions, including terminating or renegotiating the OSA. LIPA also issued a report with recommendations for improvements to PSEG LI’s structure and processes and recommended that LIPA either renegotiate or terminate the OSA.

In December 2020, LIPA filed a complaint against PSEG LI in New York State court alleging multiple breaches of the OSA in connection with PSEG LI’s preparation for and response to Tropical Storm Isaias seeking specific performance and $70 million in damages. In June 2021, LIPA and PSEG LI executed a non-binding term sheet, which includes several changes to the OSA, including shifting a portion of our fixed revenues to incentive compensation and subjecting a portion of revenue to the potential imposition of penalties by the DPS due to certain performance failures by PSEG LI, and resolves all of LIPA’s claims related to Tropical Storm Isaias and the DPS investigation. An amended OSA based on the term sheet was agreed to by the parties and approved by the LIPA Board in December 2021. In January 2022, the New York AG approved the Amended OSA and it has been submitted to the New York Comptroller for approval, which approval must occur by April 1, 2022 (such date is subject to amendment by mutual agreement of PSEG LI and LIPA) in order for the Amended OSA to become binding and effective. Such approval would result in retroactive effectiveness to January 1, 2022 for purposes of compensation. The OSA contract term will continue through 2025, with a mutual option to extend for five years. No assurances can be given regarding obtaining the New York Comptroller approval and the closing of the inquiry by the AG.

In the event that the Amended OSA is not approved by the New York Comptroller by April 1, 2022, PSEG LI intends to vigorously defend itself with regard to the allegations in LIPA’s complaint alleging breaches of the OSA. A decision in this proceeding requiring specific performance or the payment of damages by PSEG LI or resulting in the termination of the OSA could have a material adverse effect on PSEG’s results of operations and financial condition.

Climate Strategy and Sustainability Efforts

For more than a century, our mission has been to provide safe access to an around-the-clock supply of reliable, affordable energy. Building on this mission, we are working toward a future where customers universally use less energy, the energy they use is cleaner, and its delivery is safe, more reliable and more resilient. In June 2021, we accelerated and expanded our net zero vision by 20 years, establishing 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) at both PSEG Power and PSE&G (covering our electric and

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natural gas utility operations), assuming advances in technology, public policy and customer behavior. Scope 1 emissions include power generation, methane leaks, vehicle fleet emissions, sulfur hexafluoride and refrigerant leaks. Scope 2 emissions include both gas and electric purchased energy for our PSE&G facilities and line losses. In September 2021, we also committed to the United Nations-backed Race to Zero campaign. We have agreed to develop and submit science-based emission reduction targets following the criteria and recommendations of the Science Based Targets Initiative by September 2023. Targets will encompass Scopes 1, 2, and 3 (which includes downstream/customer use of energy products as well as purchased goods and services for our own operations) and must be in line with 1.5oC emissions scenarios.

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

In addition, PSE&G is committed to the safe delivery of natural gas to almost two 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 is expected to replace an additional 875 miles of gas pipes through 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 expect to reduce methane leaks by approximately 22% system wide and assuming a continuation of GSMP, we expect to achieve an overall reduction in methane emissions of approximately 60% over the 2011 through 2030 period. As noted previously, later in 2022 we will file for an extension of GSMP which would continue and accelerate these methane reductions. 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. These investments have proven effective in recent severe weather events, including Tropical Storm Ida in August 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. Our priority is to preserve the economic viability of our nuclear units, which provide over 90% of the carbon-free energy in New Jersey, by advocating for state and federal policies that recognize the value of emission-free generation and reduce market risk. We also continue to explore investment opportunities in offshore wind, both generation and transmission to support the cost-efficient connection of offshore wind generation projects to the New Jersey electric system.

Offshore Wind

In December 2020, PSEG entered into a definitive agreement with Ørsted North America Inc. (Ørsted) to acquire a 25% equity interest in Ørsted’s Ocean Wind project which is currently in development. Ocean Wind was selected by New Jersey to be the first offshore wind farm as part of the State’s intention to add 7,500 MW of offshore wind generating capacity by 2035. The Ocean Wind project is expected to achieve full commercial operation in 2025. On March 31, 2021, the BPU approved PSEG’s investment in Ocean Wind and the acquisition was completed in April 2021.

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. In December 2021, the Maryland Public Service Commission awarded Ørsted’s 846 MW Skipjack 2 project Offshore Renewable Energy Credits under Maryland’s second round of offshore wind solicitations. Skipjack 2 utilizes a portion of the GSOE lease area, and PSEG has an option to purchase 50% of Skipjack 2 and the previously awarded 120 MW Skipjack 1 project, which will be constructed concurrently. PSEG expects to determine whether to exercise this option during 2022. PSEG and Ørsted are also exploring further opportunities to develop the remaining GSOE lease area.

In April 2021, PJM announced the opening of the first public policy Order 1000 bid window that would utilize the state agreement approach for transmission projects to support New Jersey’s planned offshore wind generation. The state agreement approach requires customers in the requesting state - in this case New Jersey - to pay for the costs of these public policy transmission projects. In September 2021, PSEG and Ørsted jointly submitted several proposals in response to the solicitation, including multi-spur options and an offshore network proposal. If awarded, the projects would be developed through a 50/50 joint venture with Ørsted. The BPU has announced that it will select the winning proposals in the second half of 2022 with likely in-service dates by 2030.

Operational Excellence

We emphasize excellence in operational performance while developing opportunities in both our regulated and competitive businesses. In 2021, our utility continued its efforts to control costs while maintaining strong operational performance.

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Financial Strength

Our financial strength is predicated on a solid balance sheet, positive operating cash flow and reasonable risk-adjusted returns on increased investment. Our financial position remained strong during 2021 as we

•maintained sufficient liquidity,

•completed the sale of PSEG Power’s Solar Source units and 6,750 MW of fossil generation assets,

•maintained solid investment grade credit ratings, and

•increased our annual dividend for 2021 to $2.04 per share and our indicative annual dividend per share for 2022 to $2.16.

In late September 2021, we announced a $500 million share repurchase program to be implemented upon the close of the sale of the fossil generating assets. In November 2021, our Board of Directors authorized senior management to implement a share repurchase program at such time as senior management deemed appropriate in its discretion, whether before or after the closing of the sale of the fossil generating assets. In December 2021, under this authorization, we entered into an open market share repurchase plan for $250 million of our common shares. There were no common share repurchases during the fourth quarter of 2021. During January and through February 16, 2022, we purchased the full $250 million of common shares under the open market share repurchase plan.

We expect to be able to fund our planned capital requirements, as described in Liquidity and Capital Resources without the issuance of new equity. Our planned capital requirements, which are driven by growth in our regulated utility, and the sale of our fossil generating fleet enhances our business profile and underpins solid investment grade credit ratings with improved financial flexibility. In conjunction with the announced sale of our Fossil business, in October 2021 we redeemed all of PSEG Power’s remaining debt. see Item 8. Note 16. Debt and Credit Facilities for additional details.

Financial Results

The financial results for PSEG, PSE&G and PSEG Power for the years ended December 31, 2021 and 2020 are presented as follows:



	Years Ended December 31,
	2021		2020
	Millions, except per share data
PSE&G	$	1,446	$	1,327
PSEG Power	(2,056)		594
Other	(38)		(16)
PSEG Net Income (Loss)	$	(648)	$	1,905

PSEG Net Income (Loss) Per Share (Diluted)	$	(1.29)	$	3.76

Our 2021 Net Loss as compared to our 2020 Net Income was due to an impairment loss and related charges associated with the sale of PSEG Power’s fossil generation assets. For a more detailed discussion of our financial results, see Results of Operations.

The greater emphasis on capital spending in recent years for projects at PSE&G relative to PSEG Power, particularly those on which we receive contemporaneous returns at PSE&G has yielded strong results, which has allowed us to meet customer needs and address market conditions and investor expectations. We continue our focus on operational excellence, financial strength and disciplined investment. These guiding principles have provided the base from which we have been able to execute our strategic initiatives.

Disciplined Investment

We utilize rigorous criteria and consider a number of external factors, focusing on the value for our stakeholders, as well as other impacts, when determining how and when to efficiently deploy capital. We principally explore opportunities for investment in areas that complement our existing business and provide reasonable risk-adjusted returns and continuously assess and optimize our business mix as appropriate. In 2021, we

•made additional investments in T&D infrastructure projects on time and on budget,

•continued to execute our Energy Efficiency and other existing BPU-approved utility programs,

•closed on our acquisition of a 25% equity interest in the Ocean Wind project, and

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•continued to evaluate potential additional offshore wind opportunities, including submitting a number of proposals in response to an offshore transmission solicitation.

Regulatory, Legislative and Other Developments

In our pursuit of operational excellence, financial strength and disciplined investment, we closely monitor and engage with stakeholders on significant regulatory and legislative developments. Transmission planning rules and wholesale power market design are of particular importance to our results and we continue to advocate for policies and rules that promote fair and efficient electricity markets. For additional information about regulatory, legislative and other developments that may affect us, see Item 1. Business—Regulatory Issues.

Transmission Rate Proceedings and ROE

In March 2019, FERC issued a Notice of Inquiry seeking comments on improvements to FERC’s electric transmission incentives policy. Subsequently, in April 2021, FERC issued a supplemental notice of proposed rulemaking to eliminate the incentive for Regional Transmission Organization (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 could reduce PSE&G’s annual Net Income and annual cash inflows by approximately $30 million-$40 million.

In October 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 reduces PSE&G’s base ROE from 11.18% to 9.9% and makes several other changes regarding the recovery of certain costs. The agreement provides that the settling parties will not seek changes to our transmission formula rate for three years. We have implemented the terms of the agreement and PJM issued refunds to customers in January 2022.

Wholesale Power Market Design

In July 2021, PJM submitted to FERC a proposal to replace the extended MOPR with new provisions that accommodate state public policy programs that do not attempt to set the price of capacity. Under the PJM proposal, PSEG Power’s New Jersey nuclear plants that receive ZEC payments would not be subject to the MOPR. In September 2021, FERC issued a notice that it was not able to act on PJM’s proposed changes to the MOPR because of a split among the Commissioners on the lawfulness of PJM’s proposal. Therefore, PJM’s rules became automatically effective as of September 29, 2021 and will apply to the next base residual auction, which has been delayed. In February, FERC approved PJM’s filing requesting that the auction be held in June 2022.

In another order related to the auction, FERC found that the current rules related to the Market Seller Offer Cap were unjust and unreasonable and ultimately eliminated the default offer cap. In its place, FERC adopted a unit-specific approach to reviewing certain capacity market offers. These new rules could result in lower capacity prices since market offers for many resource types will need to be approved by the Independent Market Monitor and PJM.

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 important market reforms are being considered at the regional and national level. However, the report recommends that New Jersey continue to explore a New Jersey-only or regional competitive auction design if potential reforms at the regional and national level are not sufficient to allow New Jersey to achieve its clean energy goals. We cannot predict whether the BPU will take any measures in the future that will have an impact on the capacity market or our generating stations.

In January 2020, New Jersey rejoined the Regional Greenhouse Gas Initiative (RGGI). As a result, generating plants operating in New Jersey, including those owned by PSEG Power, that emit carbon dioxide emissions will be required to procure credits for each ton they emit. Following the close on the sale of the fossil generating assets, we no longer have generation subject to the RGGI compliance requirements.

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 will retain ownership of certain assets and liabilities

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excluded from the sale of its fossil generation business, primarily related to obligations under certain environmental regulations, including possible remediation obligations under the New Jersey Industrial Site Recovery Act and the Connecticut Transfer Act. The amounts for any such environmental remediation are not estimable, but may be material. We are also currently involved in a number of proceedings relating to sites where other hazardous substances may have been discharged and may be subject to additional proceedings in the future, and the costs and penalties of any such remediation efforts could be material.

For further information regarding the matters described above, as well as other matters that may impact our financial condition and results of operations, see Item 8. Note 15. Commitments and Contingent Liabilities.

Nuclear

In April 2019, PSEG Power’s Salem 1, Salem 2 and Hope Creek nuclear plants were awarded ZECs by the BPU. Pursuant to a process established by the BPU, ZECs are purchased from selected nuclear plants and recovered through a non-bypassable distribution charge in the amount of $0.004 per kilowatt-hour used (which is equivalent to approximately $10 per megawatt hour (MWh) generated in payments to selected nuclear plants (ZEC payment)). Each nuclear plant is expected 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 at the same approximate $10 per MWh received during the current ZEC period through May 2022 referenced above. As a result, each nuclear plant is expected to receive ZEC revenue for an additional three years starting June 2022. The terms and conditions of this April 2021 ZEC award are the same as the current ZEC period as discussed above. While the ZEC program has preserved these units to date, PSEG will simultaneously seek long-term legislative or other solutions for our New Jersey nuclear plants that sufficiently values them for their carbon-free, fuel diversity and resilience attributes. No assurances can be given regarding future ZEC awards or other long-term solutions.

The award of ZECs attaches certain obligations, including an obligation to repay the ZECs in the event that a plant ceases operations during the period that it was awarded ZECs, subject to certain exceptions specified in the ZEC legislation. PSEG Power has and will continue to recognize revenue monthly as the nuclear plants generate electricity and satisfy their performance obligations. Further, the ZEC payment may be adjusted by the BPU at any time to offset environmental or fuel diversity payments that a selected nuclear plant may receive from another source. For instance, the New Jersey Rate Counsel, in written comments filed with the BPU, has advocated for the BPU to offset market benefits resulting from New Jersey’s rejoining the RGGI from the ZEC payment. PSEG intends to vigorously defend against these arguments. Due to its preliminary nature, PSEG cannot predict the outcome of this matter.

In May 2021, the New Jersey Rate Counsel filed an appeal with the New Jersey Appellate Division of the BPU’s April 2021 decision. PSEG cannot predict the outcome of this matter.

In the event that (i) the ZEC program is overturned or is otherwise materially adversely modified through legal process; or (ii) any of the Salem 1, Salem 2 and Hope Creek plants is not sufficiently valued for its environmental, fuel diversity or resilience attributes in future periods and does not otherwise experience a material financial change that would remove the need for such attributes to be sufficiently valued, PSEG Power will take all necessary steps to cease to operate all of these plants. Alternatively, even with sufficient valuation of these attributes, if the financial condition of the plants is materially adversely impacted by changes in commodity prices, FERC’s changes to the capacity market construct (absent sufficient capacity revenues provided under a program approved by the BPU in accordance with a FERC-authorized capacity mechanism), 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 Clean Water Act and related state regulations, or other factors, PSEG Power will take all necessary steps to cease to operate all of these plants. Ceasing operations of these plants would result in a material adverse impact on PSEG’s and PSEG Power’s results of operations.

Tax Legislation

A prolonged coronavirus pandemic, further economic stimulus, or future federal and state tax legislation could have a material impact on our effective tax rate and cash tax position.

The Consolidated Appropriations Act, 2021, enacted in late December 2020, provides a 30% investment tax credit (ITC) for offshore wind projects that begin construction before December 31, 2025. In addition, on December 31, 2020, Notice 2021-05 was issued. For qualifying offshore wind projects, the notice extends the four year continuity safe harbor to ten calendar years commencing the calendar year after which construction of the project begins. This legislation and Notice will impact our offshore wind investment.

In July 2020, the Internal Revenue Service (IRS) issued final and proposed regulations addressing the limitation on deductible business interest expense contained in the Tax Cuts and Jobs 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. The portion

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of PSEG’s and PSEG Power’s business interest expense that was disallowed in 2018 and 2019 will now be deductible in those respective years.

In March 2020, the federal Coronavirus Aid, Relief, and Economic Security Act (CARES Act) was enacted. 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. The CARES Act allowed us to carry back the 2018 tax NOL generated by the final Section 163(j) regulations, which will provide a future tax benefit, subject to approval by the IRS and the Joint Committee on Taxation.

Future Outlook

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

•obtain approval of and execute on our utility capital investment program to modernize our infrastructure, improve the reliability of the service we provide to our customers, and align our sustainability and climate goals with New Jersey’s energy policy,

•focus on controlling costs while maintaining safety, reliability and customer satisfaction and complying with applicable standards and requirements,

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

•successfully manage our energy obligations and re-contract our open supply positions in response to changes in prices and demand,

•advocate for federal and state programs to properly value New Jersey’s largest carbon-free generation resource in nuclear and measures that promote fair and efficient electricity markets, including recognition of the cost of emissions,

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

•seek a fair return for our T&D investments through our transmission formula rate, distribution infrastructure and clean energy investment programs and periodic distribution base rate case proceedings,

•successfully operate the LIPA T&D system and manage LIPA’s fuel supply and generation dispatch obligations, and

•manage the risks and opportunities in environmental, social and governance (ESG) matters, which is an integral part of our long-term strategy to be a clean energy leader for the benefit of all stakeholders.

In addition to the risks described elsewhere in this Form 10-K for 2021 and beyond, the key issues and challenges we expect our business to confront include:

•regulatory and political uncertainty, both with regard to future energy policy, design of energy and capacity markets, transmission policy and environmental regulation, as well as with respect to the outcome of any legal, regulatory or other proceedings,

•the continuing impact of the ongoing coronavirus pandemic and the associated regulations and economic impacts, which could extend beyond the duration of the pandemic,

•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 stockholder value and address the interests of our multiple stakeholders. In assessing our options, we consider a wide variety of factors, including the performance and prospects of our businesses; the views of investors, regulators, 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,

•the further disposition or restructuring of our merchant generation business or portions thereof beyond the aforementioned sale of PSEG Power’s fossil and solar generating assets or other existing businesses or the acquisition or development of new businesses,

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•investments in regional offshore wind with long-term contracts or regulated transmission returns that provide revenue predictability and a reasonable risk-adjusted return,

•continued operation of our nuclear generation facilities, to the extent there is sufficient certainty that their operation will render an acceptable risk-adjusted return, and

•acquisitions, dispositions 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.

RESULTS OF OPERATIONS



	Years Ended December 31,
	2021		2020		2019
Earnings (Losses)	Millions
PSE&G	$	1,446	$	1,327	$	1,250
PSEG Power (A)	(2,056)		594		468
Other (B)	(38)		(16)		(25)
PSEG Net Income (Loss)	$	(648)	$	1,905	$	1,693

PSEG Net Income (Loss) Per Share (Diluted)	$	(1.29)	$	3.76	$	3.33

(A)PSEG Power’s 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. PSEG Power’s results in 2020 include an after-tax gain of $86 million related to the sale of its ownership interest in the Yards Creek generation facility. PSEG Power’s results in 2019 include an after-tax loss of $286 million related to the sale of its ownership interests in the Keystone and Conemaugh fossil generation plants. See Item 8. Note 4. Early Plant Retirements/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 attributable to changes related to the NDT Fund and MTM are shown in the following table:



	Years Ended December 31,
	2021		2020		2019
	Millions, after tax
NDT Fund and Related Activity (A) (B)	$	108	$	137	$	152
Non-Trading MTM Gains (Losses) (C)	$	(446)	$	(58)	$	205

(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 11. Trust Investments for additional information. NDT Fund Income (Expense) also includes interest and dividend income and other costs related to the NDT Fund recorded in Other Income (Deductions), interest accretion expense on PSEG Power’s nuclear Asset Retirement Obligation (ARO) recorded in Operation & 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 $(70) million, $(94) million and $(103) million for the years ended December 31, 2021, 2020 and 2019, respectively.

(C)Net of tax (expense) benefit of $174 million, $23 million and $(80) million for the years ended December 31, 2021, 2020 and 2019, respectively.

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The Net Loss in 2021 as compared to Net Income in 2020 was driven primarily by

•an impairment loss and related charges taken as a result of the sale of the fossil generation assets at PSEG Power (see Item 8. Note 4. Early Plant Retirements/Asset Dispositions and Impairments for additional information),

•higher MTM losses at PSEG Power due to rising energy prices, and

•a gain on the sale of PSEG Power’s ownership interest in the Yards Creek generation facility in 2020,

•partially offset by higher earnings due to continued investments in T&D programs at PSE&G, and

•higher pension and OPEB credits.

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 26. Related-Party Transactions.



							Increase / (Decrease)			Increase / (Decrease)
	Years Ended December 31,
	2021		2020		2019		2021 vs. 2020			2020 vs. 2019
	Millions						Millions		%	Millions		%
Operating Revenues	$	9,722	$	9,603	$	10,076	$	119	1	$	(473)	(5)
Energy Costs	3,499		3,056		3,372		443		14	(316)		(9)
Operation and Maintenance	3,226		3,115		3,111		111		4	4		—
Depreciation and Amortization	1,216		1,285		1,248		(69)		(5)	37		3
(Gains) Losses on Asset Dispositions and Impairments	2,637		(123)		402		2,760		N/A	(525)		N/A
Income from Equity Method Investments	16		14		14		2		14	—		—
Net Gains (Losses) on Trust Investments	194		253		260		(59)		(23)	(7)		(3)
Other Income (Deductions)	98		115		125		(17)		(15)	(10)		(8)
Non-Operating Pension and OPEB Credits (Costs)	328		249		177		79		32	72		41
Loss on Extinguishment of Debt	(298)		—		—		(298)		N/A	—		N/A
Interest Expense	571		600		569		(29)		(5)	31		5
Income Tax (Benefit) Expense	(441)		396		257		(837)		N/A	139		54

The 2021, 2020 and 2019 amounts in the preceding table for Operating Revenues and O&M costs each include $511 million, $520 million and $490 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 5. Variable Interest Entities for additional information. The following discussions for PSE&G and PSEG Power provide a detailed explanation of their respective variances.

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PSE&G



	Years Ended December 31,						Increase / (Decrease)			Increase / (Decrease)
	2021		2020		2019		2021 vs. 2020			2020 vs. 2019
	Millions						Millions		%	Millions		%
Operating Revenues	$	7,122	$	6,608	$	6,625	$	514	8	$	(17)	—
Energy Costs	2,688		2,469		2,738		219		9	(269)		(10)
Operation and Maintenance	1,692		1,614		1,581		78		5	33		2
Depreciation and Amortization	928		887		837		41		5	50		6
Gain on Asset Dispositions	(4)		(1)		—		(3)		N/A	(1)		N/A
Net Gains (Losses) on Trust Investments	2		3		2		(1)		(33)	1		50
Other Income (Deductions)	88		108		83		(20)		(19)	25		30
Non-Operating Pension and OPEB Credits (Costs)	264		205		150		59		29	55		37
Interest Expense	402		388		361		14		4	27		7
Income Tax Expense	324		240		93		84		35	147		N/A

Year Ended December 31, 2021 as compared to 2020

Operating Revenues increased $514 million due to changes in delivery, clause, commodity and other operating revenues.

Delivery Revenues increased $221 million.

•Transmission revenues increased $113 million due to higher revenue requirements calculated through our transmission formula rate, primarily to recover required investments. The net increase in 2021 includes a reduction to the revenue requirement of approximately $64 million as a result of our ROE settlement approved by FERC effective August 1, 2021, partially offset by a $35 million flowback of certain excess deferred income taxes in 2020. The $35 million flowback was offset in Income Tax Expense in 2020.

•Gas distribution revenues increased $65 million due to increases of $42 million from collection of the GSMP in base rates, $18 million in CIP decoupling revenues, $7 million in collections of Green Program Recovery Charges (GPRC) and $7 million from higher sales volumes. These increases were partially offset by a decrease of $9 million in WNC revenues.

•Electric distribution revenues increased $59 million due primarily to $30 million from CIP decoupling revenue, $13 million in higher collections of GPRC, $9 million from an Energy Strong II rate roll-in and $7 million from higher sales volumes.

•Electric distribution and gas distribution revenue requirements were $16 million lower as a result of the flowback of excess deferred income tax liabilities and tax repair-related accumulated deferred income taxes. This decrease is offset in Income Tax Expense.

Clause Revenues increased $47 million due to $17 million in Tax Adjustment Credits (TAC) and GPRC deferrals, $28 million in higher Societal Benefits Charges (SBC) and $4 million in Margin Adjustment Clause (MAC) revenues. These increases were partially offset by $2 million in lower Solar Pilot Recovery Charge (SPRC) collections. The changes in TAC and GPRC Deferrals, SBC, MAC and SPRC collections were entirely offset by the amortization of related costs (Regulatory Assets) in O&M, D&A and Interest and Tax Expenses. PSE&G does not earn margin on TAC or GPRC deferrals or on SBC, MAC or SPRC collections.

Commodity Revenues increased $217 million due to higher 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 BGS to retail customers.

•Gas revenues increased $143 million due primarily to higher BGSS prices of $110 million and higher BGSS sales volumes of $33 million.

•Electric revenues increased $74 million due to $118 million from higher BGS sales volumes, partially offset by $44 million from lower prices.

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Other Operating Revenues increased $29 million due to a $27 million increase primarily in appliance service revenues and a $25 million increase from the sale of Transition Renewable Energy Certificates (TREC). These increases were partially offset by a $20 million reduction in revenues from Solar Renewable Energy Credits (SREC) and a $3 million reduction in ZEC revenues. The changes in TREC, SREC and ZEC revenues are entirely offset by changes to Energy Costs.

Operating Expenses

Energy Costs increased $219 million. This is entirely offset by changes in Commodity Revenues and Other Operating Revenues.

Operation and Maintenance increased $78 million due primarily to increases of $46 million in clause and renewable expenditures, $16 million in appliance service costs, $11 million in transmission maintenance expenditures and $5 million in other operating expenses.

Depreciation and Amortization increased $41 million due primarily to an increase in depreciation of $55 million due to additional plant placed into service and a $6 million increase from the amortization of software. These increases were partially offset by a $19 million decrease due to lower transmission depreciation rates effective August 1, 2021, which were included in the settlement of the formula rate and other matters.

Other Income (Deductions) decreased $20 million due primarily to a decrease of $16 million in the Allowance for Funds Used During Construction (AFUDC) from lower transmission expenditures and a $4 million net decrease in solar loan interest and miscellaneous other income.

Non-Operating Pension and OPEB Credits (Costs) increased $59 million due primarily to a $44 million decrease in interest cost and a $27 million increase in the expected return on plan assets, partially offset by a $6 million net increase in the amortization of net prior service cost and a $6 million net increase in amortization of the net actuarial loss.

Interest Expense increased $14 million due primarily to increases of $6 million and $3 million due to net long-term debt issuances in 2021 and 2020, respectively, and a $5 million increase due primarily to lower AFUDC.

Income Tax Expense increased $84 million due primarily to higher pre-tax income in 2021 and reduced flowback of excess deferred income tax liabilities in 2021, partially offset by the tax benefit from the CEF program investments.

Year Ended December 31, 2020 as compared to 2019

See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations in our 2020 Annual Report.

PSEG Power



	Years Ended December 31,						Increase / (Decrease)			Increase / (Decrease)
	2021		2020		2019		2021 vs. 2020			2020 vs. 2019
	Millions						Millions		%	Millions		%
Operating Revenues	$	3,147	$	3,634	$	4,385	$	(487)	(13)	$	(751)	(17)
Energy Costs	1,978		1,821		2,118		157		9	(297)		(14)
Operation and Maintenance	983		964		1,040		19		2	(76)		(7)
Depreciation and Amortization	256		368		377		(112)		(30)	(9)		(2)
(Gains) Losses on Asset Dispositions and Impairments	2,641		(122)		402		2,763		N/A	(524)		N/A
Income from Equity Method Investments	16		14		14		2		14	—		—
Net Gains (Losses) on Trust Investments	187		241		253		(54)		(22)	(12)		(5)
Other Income (Deductions)	29		12		54		17		N/A	(42)		N/A
Non-Operating Pension and OPEB Credits (Costs)	47		33		21		14		42	12		57
Loss on Extinguishment of Debt	(298)		—		—		(298)		N/A	—		N/A
Interest Expense	78		121		119		(43)		(36)	2		2
Income Tax Expense (Benefit)	(752)		188		203		(940)		N/A	(15)		(7)

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Year Ended December 31, 2021 as compared to 2020

Operating Revenues decreased $487 million due to changes in generation, gas supply and other operating revenues.

Generation Revenues decreased $668 million due primarily to

•a net decrease of $606 million due to higher MTM losses in 2021 as compared to 2020. Of this amount, there was a $624 million decrease due to changes in forward prices, partially offset by an $18 million increase due to less losses on positions reclassified to realized upon settlement in 2021,

•a net decrease of $288 million due primarily to $201 million from lower volumes of electricity sold under the BGS contracts, coupled with an $87 million impact from the transfer of responsibility for firm transmission services from BGS suppliers to the Electric Distribution Companies (EDCs), and

•a net decrease of $29 million in solar revenues due to the sale of the solar plants in June 2021,

•partially offset by a net increase of $188 million due primarily to higher average realized prices and higher volumes sold in the PJM, New England (NE) and New York (NY) regions, and

•a net increase of $64 million in capacity revenues due primarily to increases in auction prices, coupled with decreases in capacity charges due to lower BGS and other load obligations in the PJM region, partially offset by lower capacity prices and the retirement of the Bridgeport Harbor 3 (BH3) coal plant in the NE region.

Gas Supply Revenues increased $182 million due primarily to

•a net increase of $106 million in sales under the BGSS contract due primarily to higher prices of $72 million and higher sales volumes of $34 million, and

•a net increase of $74 million related to sales to third parties, of which $90 million was due to higher average sales prices, partially offset by $16 million due to lower volumes sold.

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 increased $157 million due to

Generation costs decreased $13 million due primarily to

•a net decrease of $147 million in transmission costs due primarily to an $87 million impact from the transfer of responsibility for firm transmission services under BGS contracts from BGS suppliers to the EDCs, coupled with a $60 million decrease in other transmission costs, mainly from lower volumes of electricity sold under the BGS contracts, and

•a net decrease of $66 million due to higher net MTM gains in 2021. Of this amount, there was a $52 million decrease due to changes in forward prices, coupled with a $14 million decrease due to more gains on positions reclassified to realized upon settlement in 2021,

•partially offset by a net increase of $157 million in fuel costs, reflecting higher gas prices and higher volumes in the PJM, NY, and NE regions, and

•a net increase of $42 million in energy purchases due primarily to an increase in purchased volumes in the PJM region to meet physical energy sales. This was partially offset by a decrease in renewable energy credit requirements caused by decreases in load served in the PJM region.

Gas costs increased $170 million due primarily to

•a net increase of $103 million in costs related to sales under the BGSS contract, of which $74 million was due to the higher average cost of gas and $29 million to higher send out volumes. Included in the 2020 average cost of gas were $18 million of interstate gas pipeline refunds due to a settlement on pipeline rates from prior periods, and

•a net increase of $67 million related to sales to third parties, of which $81 million was due to an increase in the average cost of gas, partially offset by a decrease of $14 million due to lower volumes sold.

Operation and Maintenance increased $19 million due primarily to a refueling outage in 2021 at our 100%-owned Hope Creek nuclear plant as compared to an outage in 2020 at our 57%-owned Salem 2 nuclear plant and severance costs related to the sale of the fossil generating plants, partially offset by lower costs in 2021 due to the sale of our ownership interest in the solar plants in June 2021.

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Depreciation and Amortization decreased $112 million due primarily to ceasing depreciation expense on the fossil generating plants, the sale of the solar plants and the retirement of BH3 in 2021.

(Gains) Losses on Asset Dispositions and Impairments. The loss in 2021 primarily reflects a $2,691 million impairment due to the sale of the fossil generating plants and other impairments, partially offset by a $63 million gain from the sale of the solar plants. The $122 million gain in 2020 was due to the sale of our ownership interest in the Yards Creek generation facility. See Item 8. Note 4. Early Plant Retirements/Asset Dispositions and Impairments.

Net Gains (Losses) on Trust Investments decreased $54 million due primarily to a $101 million decrease in net unrealized gains on equity investments in the NDT Fund, partially offset by a $46 million increase in net realized gains on NDT Fund investments.

Other Income (Deductions) increased $17 million due primarily to less purchases of NOL tax benefits under the New Jersey Technology Tax Benefit Transfer Program and higher interest and dividend income on NDT Fund investments in 2021.

Non-Operating Pension and OPEB Credits (Costs) increased $14 million due to a decrease in interest cost and an increase in the expected return on plan assets, partially offset by an increase in the amortization of net prior service cost.

Loss on Extinguishment of Debt represents a loss incurred in 2021 for a make whole premium that was payable upon early redemption of all outstanding debt obligations and other non-cash debt extinguishment costs.

Interest Expense decreased $43 million due primarily to the early redemption of all remaining outstanding Senior Notes in October 2021.

Income Tax Expense decreased $940 million due primarily to lower pre-tax income in 2021, partially offset by the recapture of ITCs related to the sale of the solar plants in 2021, the tax benefit in 2020 from changes in uncertain tax positions as a result of the settlement of the 2011-2016 federal income tax audits, and the purchase of less New Jersey NOL tax benefits in 2021.

Year Ended December 31, 2020 as compared to 2019

See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations in our 2019 Annual Report.

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 $600 million 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 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 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’s available sources of external liquidity may include the issuance of long-term debt securities and the incurrence of additional indebtedness under credit facilities. Our current sources of external liquidity include multi-year revolving credit facilities totaling $1.5 billion. These facilities are available to back-stop PSEG’s commercial paper program, issue letters of credit and for general corporate purposes. PSEG’s credit facilities 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 $1.9 billion of multi-year revolving 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

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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, 2021, our operating cash flow decreased $1,366 million. The net decrease was primarily due to a $780 million reduction related to net cash collateral posting requirements at PSEG Power and a net change at PSE&G, as discussed below. In addition, in 2021, there were higher tax payments at PSEG Power and lower tax refunds at the parent company, partially offset by lower tax payments at Energy Holdings.

Current economic conditions have adversely impacted residential and C&I customer payment patterns. During the moratorium, as previously discussed, PSE&G has experienced a significant decrease in cash inflow and higher Accounts Receivable aging and an associated increase in bad debt expense, which we expect will extend beyond the duration of the coronavirus pandemic.

PSE&G

PSE&G’s operating cash flow decreased $229 million from $1,953 million to $1,724 million for the year ended December 31, 2021, as compared to 2020, due primarily to a net increase in regulatory deferrals, increases in electric energy and vendor payments, and higher tax payments in 2021, partially offset by higher earnings.

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 facilities.

We continually monitor our liquidity and seek to add capacity as needed to meet our liquidity requirements. Each of our credit facilities is restricted as to availability and use to the specific companies as listed below; however, if necessary, the PSEG facilities can also be used to support our subsidiaries’ liquidity needs.

As part of the generation business, we hedge generation output to mitigate market price volatility. When prices increase, hedged positions could be out-of-the-money, requiring margin postings. In times of significantly rising market prices, those collateral postings could be substantial. During the second half of 2021, PSEG Power experienced a substantial increase in net cash collateral postings related to hedge positions that are out-of-the-money due to an increase in energy market prices, from $343 million at the end of June to $844 million at the end of December. PSEG issued short-term borrowings, including commercial paper, in order to satisfy the increase in collateral postings and to prepare for the PSEG Power debt redemption. In October, PSEG Power borrowed $755 million from its credit facility to support its Senior Notes redemption and additional cash collateral postings, as needed. In November, PSEG issued $1.5 billion of Senior Notes, using a portion of the funds to provide support to PSEG Power for paying off the $755 million loan from the credit facility.

In March 2020, PSEG entered into a $300 million, 364-day term loan agreement which was prepaid in January 2021. In March and May 2021, PSEG entered into two 364-day variable rate term loan agreements for $500 million and $750 million, respectively. In August 2021, PSEG entered into a $1.25 billion, 364-day variable rate term loan agreement. These term loans are not included in the credit facility amounts presented in the following table.

Our total credit facilities and available liquidity as of December 31, 2021 were as follows:



Company/Facility	As of December 31, 2021
	Total Facility		Usage		Available Liquidity
	Millions
PSEG	$	1,500	$	1,022	$	478
PSE&G	600		18		582
PSEG Power	2,000		145		1,855
Total	$	4,100	$	1,185	$	2,915

For additional information, see Item 8. Note 16. Debt and Credit Facilities.

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As of December 31, 2021, our credit facility capacity was in excess of our projected maximum liquidity requirements over our 12 month planning horizon, including access to external financing to meet redemptions. Our maximum liquidity requirements are based on stress scenarios that incorporate 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 $1,151 million and $840 million as of December 31, 2021 and 2020, respectively. See Item 8. Note 15. Commitments and Contingent Liabilities for additional discussion of PSEG Power’s agreements.

Long-Term Debt Financing

During the fourth quarter of 2021 PSEG:

•issued $750 million of 0.84% Senior Notes due November 2023,

•issued $750 million of 2.45% Senior Notes due November 2031, and

•retired $300 million of 2.00% Senior Notes at maturity.

In October 2021, PSEG redeemed all remaining outstanding Senior Notes of PSEG Power due to covenants that could trigger a default from the sale of PSEG Power’s fossil generating plants. This included $700 million of 3.85% Senior Notes due to mature in June 2023, $250 million of 4.30% Senior Notes due to mature in November 2023, and $404 million of 8.63% Senior Notes due to mature in April 2031. These Senior Notes were redeemed at a redemption price that included a "make-whole" premium of approximately $294 million plus any interest accrued and unpaid to the redemption date, in each case, calculated in accordance with the indenture governing the Senior Notes. The debt redemption and “make-whole” premium were funded with a short-term loan from PSEG and borrowings under PSEG Power’s credit facility. In addition, approximately $4 million of other non-cash debt extinguishment costs related to the redemption were recorded in October 2021.

During the next twelve months,

•PSEG has $700 million of 2.65% Senior Notes maturing in November 2022.

For additional information, see Item 8. Note 16. Debt and Credit Facilities.

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, 2021, PSE&G’s Mortgage coverage ratio was 4.7 to 1 and the Mortgage would permit up to approximately $8.4 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 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. PSEG Power’s bank credit agreements also contain limitations on the incurrence of subsidiary debt and liens.

There are no cross-acceleration provisions in PSEG’s or PSE&G’s indentures. However, 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.

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In March 2021, each of PSEG and PSEG Power and its subsidiaries received waivers from the lenders and the administrative agent under their existing credit agreements permitting them to divest, in one or more transactions, some or all of its and its subsidiaries’ non-nuclear assets without breaching the terms of the agreements.

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 likely 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	2021		2020		2019
Per Share	$	2.04	$	1.96	$	1.88
in Millions	$	1,031	$	991	$	950

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. In May 2021, Moody’s changed PSE&G’s outlook to Negative from Stable. In August 2021, Moody’s changed PSEG and PSEG Power’s outlook to Negative from Stable. In October 2021, Moody’s downgraded PSEG’s senior unsecured notes rating to Baa2 from Baa1, PSE&G’s mortgage bond rating to A1 from Aa3 and commercial paper rating to P2 from P1, and assigned PSEG Power an Issuer Credit Rating of Baa2. Moody’s outlooks of PSEG, PSE&G and PSEG Power were changed to Stable from Negative. With the redemption of PSEG Power’s Senior Notes, S&P maintains an Issuer Credit Rating of BBB. 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

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, 2021, we had Other Comprehensive Income of $154 million on a consolidated basis. The Other Comprehensive Income was due primarily to an increase of $190 million related to pension and other postretirement benefits, and $3 million of unrealized gains on derivative contracts accounted for as hedges, partially offset by $39 million of net unrealized losses related to Available-for-Sale Debt Securities. See Item 8. Note 23. 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 AFUDC 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.



	2022		2023		2024
			Millions
PSE&G:
Transmission	$	865	$	800	$	595
Electric Distribution	840		1,185		810
Gas Distribution	940		1090		735
Clean Energy	275		390		390
Total PSE&G	$	2,920	$	3,465	$	2,530
Other	140		180		210
Total PSEG	$	3,060	$	3,645	$	2,740

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 energy efficiency programs, infrastructure supporting electric vehicles and grid-connected solar.

In 2021, PSE&G made $2,447 million of capital expenditures, primarily for T&D system reliability. This does not include expenditures for cost of removal, net of salvage, of $121 million, which are included in operating cash flows.

Other

PSEG’s other projected expenditures are primarily comprised of investments to replace major parts and enhance operational performance at PSEG Power.

In 2021, PSEG’s other capital expenditures were $115 million, excluding $157 million for nuclear fuel, primarily related to various nuclear projects at PSEG Power.

Offshore Wind

The above table does not reflect our expected long-term investments in offshore wind projects. We currently expect to make investments in our 25% equity interest in Orsted’s Ocean Wind project to fund construction and operations planning activities. Over the course of the project, which is expected to achieve full commercial operation in 2025, our investments are expected to be substantial. We have planned funding of approximately $250 million to support continued project development to its final investment decision. At that time, if we choose not to proceed with the project, Orsted has the option to repurchase our 25% equity interest in order to proceed with the project.

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 16. Debt and Credit Facilities, Note 8. Leases and Note 15. Commitments and Contingent Liabilities.

The table below does not reflect any anticipated cash payments for pension and OPEB or asset retirement obligations due to uncertain timing of payments. See Item 8. Note 14. Pension and Other Postretirement Benefits (OPEB) and Savings Plans and Note 13. 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	$	4,146	$	700	$	1,500	$	550	$	1,396
PSE&G	11,890		—		1,575		1,225		9,090

Interest on Recourse Debt
PSEG	444		86		118		75		165
PSE&G	6,726		407		781		694		4,844

Operating Leases
PSE&G	117		15		22		17		63
Other	152		25		36		31		60

Energy-Related Purchase Commitments
PSEG Power	2,274		697		825		494		258
Total	$	25,749	$	1,930	$	4,857	$	3,086	$	15,876

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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, 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 the 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 long-term rate of return on trust 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	2021		2020		2019
Pension
Discount Rate	2.94	%	2.61	%	3.30	%
Expected Rate of Return on Plan Assets	7.70	%	7.70	%	7.80	%
OPEB
Discount Rate	2.82	%	2.46	%	3.20	%
Expected Rate of Return on Plan Assets	7.69	%	7.70	%	7.79	%

The discount rate used to calculate 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 the Pension Plan, the excess would be amortized over the average remaining expected life of inactive participants, which is approximately nineteen years. For Pension Plan II, the excess would be amortized over the average remaining service period of active employees, which is approximately fourteen years.

Effect if Different Assumptions Used: As part of the business planning process, we have modeled future costs assuming a 7.20% expected rate of return and a 2.94% discount rate for 2022 pension costs/credits and a 2.82% discount rate for 2022 OPEB costs/credits. Based upon these assumptions, we have estimated a net periodic pension credit in 2022 of approximately $115 million, or $172 million, net of amounts capitalized, and a net periodic OPEB credit in 2022 of approximately $124 million, or $127 million, net of amounts capitalized. 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.

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The following chart reflects the sensitivities associated with a change in certain assumptions. The effects of the assumption changes shown below solely reflect the impact of that specific assumption.



	% Change	Impact on Benefit Obligation as of December 31, 2021		Increase to Costs in 2022		Increase to Costs, net of Amounts Capitalized in 2022
Assumption		Millions
Pension
Discount Rate	(1)%	$	945	$	32	$	21
Expected Rate of Return on Plan Assets	(1)%	N/A		$	67	$	67
OPEB
Discount Rate	(1)%	$	131	$	15	$	15
Expected Rate of Return on Plan Assets	(1)%	N/A		$	6	$	6

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. Fair values of other energy contracts may be based on broker quotes.

For a small number of contracts where limited observable inputs or pricing information are available, modeling techniques are employed in determination of their fair value using assumptions reflective of contractual terms, current market rates, forward price curves, discount rates and risk factors, as applicable.

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 18. Financial Risk Management Activities and Note 19. 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.

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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 generation units are evaluated at the ISO regional portfolio level and, effective in August 2021 for PJM assets, do not include PSEG’s fossil generating assets as they are classified as Held for Sale. In certain cases, generation assets are evaluated on an individual basis where those assets are individually contracted on a long-term basis with a third party and operations are independent of other generation assets such as PSEG Power’s Kalaeloa facility. These tests require significant estimates and judgment when developing expected future cash flows. Significant inputs include, but are not limited to, forward power prices (including ZEC payments for the New Jersey nuclear assets), fuel costs, dispatch rates, 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 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, makes 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 4. Early Plant Retirements/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 more than 75% or $1,201 million of PSEG’s total AROs as of December 31, 2021. 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:

•financial feasibility and impacts on potential early shutdown,

•license renewals,

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•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, and

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

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. As of December 31, 2021, assumed market discount rates were historically low; therefore, changes in assumptions may have a more significant impact on the recorded ARO. Had the following assumptions been applied, our estimates of the approximate impacts on the Nuclear ARO as of December 31, 2021 are as follows:

•A decrease of 1% in the discount rate would result in a $130 million increase in the Nuclear ARO.

•An increase of 1% in the inflation rate would result in a $1,321 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 $339 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 $1,020 million.

•If PSEG Power were to increase its early shutdown probability to 100% and retire Salem 1 and Hope Creek starting in 2025 and Salem 2 in 2026, which is significantly earlier than the end of their current license periods, the Nuclear ARO would increase by $698 million. For additional information, see Item 8. Note 4. Early Plant Retirements/Asset Dispositions and Impairments.

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 7. Regulatory Assets and Liabilities for a description of the amounts and nature of regulatory balance sheet amounts.

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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 and options with approved counterparties. These contracts, in conjunction with physical sales and other services, help reduce risk and optimize the value of owned electric generation capacity.

Value-at-Risk (VaR) Models

VaR represents the potential losses, under normal market conditions, for instruments or portfolios due to changes in market factors, for a specified time period and confidence level. We estimate VaR across our commodity businesses.

MTM VaR consists of MTM derivatives that are economic hedges. The MTM VaR calculation does not include market risks associated with activities that are subject to accrual accounting, primarily our generating facilities and some load-serving 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,
	2021		2020
	Millions
95% Confidence Level, Loss could exceed VaR one day in 20 days
Period End	$	71	$	16
Average for the Period	$	36	$	10
High	$	113	$	18
Low	$	7	$	5

99.5% Confidence Level, Loss could exceed VaR one day in 200 days
Period End	$	112	$	24
Average for the Period	$	57	$	16
High	$	178	$	29
Low	$	11	$	8

See Item 8. Note 18. 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, 2021, a hypothetical 10% increase in market interest rates would result in

•no material impact on annual interest costs related to either the current or the long-term portion of long-term debt, and

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•a $421 million decrease in the fair value of debt, including a $385 million decrease at PSE&G and a $36 million decrease at PSEG.

Debt and Equity Securities

As of December 31, 2021, we had $7.5 billion of net assets in a 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, 2021, the portfolio included $1.3 billion of equity securities and $1.3 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, 2021, a hypothetical 10% change in the equity market would impact the value of the equity securities in the NDT Fund by approximately $130 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 6.78 years and a yield of 1.76%. The portfolio’s value will appreciate or depreciate by the duration with a 1% change in interest rates. As of December 31, 2021, a hypothetical 1% increase in interest rates would result in a decline in the market value for the fixed income portfolio of approximately $90 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, 2021 and 2020, the related consolidated statements of operations, comprehensive income, stockholders' equity, and cash flows, for each of the three years in the period ended December 31, 2021, 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 consolidated financial position of the Company as of December 31, 2021 and 2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2021, 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, 2021, 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 24, 2022, 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 Matters

The critical audit matters communicated below are matters arising from the current-period audit of the financial statements that were communicated or required to be communicated to the audit committee and that (1) relate 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 matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.

Asset Retirement Obligations (“AROs”) - Nuclear Decommissioning- Refer to Notes 4 and 13 to the financial statements

Critical Audit Matter Description

PSEG’s wholly-owned subsidiary PSEG Power LLC (PSEG Power) owns and operates nuclear plants and has recorded associated asset retirement obligations (AROs) for their eventual decommissioning. In estimating its AROs for the nuclear plants, PSEG Power develops probability-weighted cash flow scenarios which, on a unit-by-unit basis, consider 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. Management updates its cost studies triennially unless circumstances warrant more frequent updates. The most recent cost study was performed in 2021.

We identified nuclear decommissioning AROs as a critical audit matter because of the significant estimates and assumptions made by management and management’s specialist in determining the recorded AROs. Auditing each of these assumptions required a high degree of auditor judgment and, for certain assumptions and cost studies, the use of environmental and fair value specialists.

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How the Critical Audit Matter Was Addressed in the Audit

Our audit procedures related to the nuclear decommissioning ARO included the following, among others:

•We tested the effectiveness of controls over assumptions used in the calculation, including the evaluation of retirement date assumptions, cost estimates, and the probability weighting of the various cash flow scenarios.

•We evaluated management’s assumptions used in calculating the recorded nuclear decommissioning ARO balance including estimates of spent fuel cost reimbursements and weighted probabilities of various cash flow scenarios considering potential early retirement of the New Jersey nuclear plants and decommissioning methods.

•With the assistance of our environmental specialists and internal fair value specialists, we evaluated management’s judgments related to significant assumptions used in calculating the ARO including estimated decommissioning costs, discount rate, and inflation rate by:

◦Evaluating the experience, qualifications, and objectivity of management’s specialist;

◦Understanding the methodology used by management in developing estimates of the nuclear ARO;

◦Assessing the basis of and supporting evidence for information used in the determination of significant ARO assumptions;

◦Testing the mathematic accuracy of the models used to calculate the ARO;

•We evaluated the disclosures related to the estimated nuclear decommissioning costs, including the balances recorded.

Asset Dispositions –Sale of Fossil Assets — Refer to Note 4 to the financial statements

Critical Audit Matter Description

As disclosed in Note 4, in August 2021, PSEG entered into agreements to sell PSEG Power’s entire portfolio of fossil generating assets to newly formed subsidiaries of ArcLight Energy Partners Fund VII, L.P. As a result of the Board of Directors’ approval of the transactions, PSEG fossil generating assets and liabilities to be disposed were reclassified to Assets and Liabilities Held for Sale. During 2021, PSEG recorded impairment losses of approximately $2,691 million associated with the planned disposition of the fossil assets.

We identified the accounting for the sale of the fossil assets as a critical audit matter because the transaction relates to accounts and disclosures that are material to the financial statements and the evaluation of the applicable accounting guidance was complex. Further, auditing the transactions involved extensive audit effort, including the use of professionals with specialized skill and knowledge to assist in performing procedures related to the timing of recognition of the impairments and in the evaluation of the presentation and disclosure in the financial statements.

How the Critical Audit Matter Was Addressed in the Audit

Our audit procedures related to the accounting for the sale of the fossil assets included the following, among others:

•We tested the effectiveness of controls over management’s impairment tests, including considerations of asset groupings, the timing of impairment charges recorded, the significant inputs utilized to determine estimated undiscounted cash flows, and the weighted probabilities assigned to the outcome of various scenarios.

•We tested the effectiveness of controls over management’s evaluation for the accounting for sale of the assets, including considerations as to the timing of meeting the classification of assets and liabilities held for sale, the amounts recorded as assets and liabilities held for sale, impairment charges recorded, and evaluation of the presentation and disclosure in the financial statements.

•For impairment tests performed prior to the signing of the sale agreements, we evaluated the weighted probabilities assigned to the outcomes of various cash flow scenarios. Additionally, with the assistance of our fair value specialists, we evaluated the significant inputs and assumptions utilized within management’s impairment tests, including forward power prices, fuel costs, dispatch rates and estimates of the fair value to be received upon any disposition of assets.

•We obtained and read the sale agreements and, with the assistance of professionals with specialized skills and knowledge, evaluated management’s conclusions on the accounting treatment for the sale agreements.

•We evaluated the disclosures related to the sale of fossil assets, including the balances recorded.

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Regulatory Assets and Liabilities – Income Taxes —Refer to Notes 1, 7, and 22 to the financial statements

Critical Audit Matter Description

PSEG’s subsidiary, Public Service Electric and Gas Company (PSE&G), is an electric and gas transmission and distribution utility regulated by the Board of Public Utilities (BPU) and the Federal Energy Regulatory Commission. 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 cost-based rate regulation. Through the rate-making process, PSE&G’s rates to customers also include the recovery of income tax expense associated with PSE&G’s electric and gas distribution and electric transmission operations. PSE&G has recorded regulatory liabilities for excess accumulated deferred income taxes (ADIT) which will be refunded to customers in future periods. PSE&G’s most recent electric and gas distribution base rate case, concluded in 2018, established the tax adjustment credit (TAC) that provides for the refund of these excess ADIT regulatory liabilities as well as the flow through to customers of historical and current accumulated deferred income taxes for tax-deductible repairs. The flow through of the tax benefits results in lower revenues and lower income tax expense, as well as the recognition of a regulatory asset as management believes it is probable that the accumulated tax benefits treated as a flow-through item to PSE&G customers will be recovered from customers in the future.

We identified the accounting for the TAC as a critical audit matter due to the complexity in accounting for the impact of rate regulation on income tax expense. Auditing management’s assertion that the TAC regulatory assets are probable of future recovery, and that the accounting for the TAC is accurately recorded and reported, requires auditor judgment and specialized knowledge of accounting matters specific to rate regulation. Further, the determination of the estimated benefit of current tax-deductible repairs under the Internal Revenue Code, and the resulting impacts on the TAC regulatory asset and income tax expense recorded in the financial statements, is complex, and required a high degree of auditor judgment and the involvement of our income tax specialists.

How the Critical Audit Matter Was Addressed in the Audit

Our audit procedures to evaluate the accounting for the TAC and the associated regulatory assets, regulatory liabilities, and income tax expense included the following, among others:

•We tested the effectiveness of controls over the calculation of the amounts refunded through the TAC, including controls over the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering the TAC regulatory assets in future rates.

•We evaluated management’s analysis over the assertion that the TAC regulatory assets are probable of recovery.

•We evaluated relevant regulatory orders related to the ratemaking treatment of income taxes.

•With the assistance of our income tax specialists, we tested the accuracy of income tax expense, regulatory assets and regulatory liabilities associated with the TAC.

•We evaluated the financial statement presentation and disclosures related to TAC, including the balances recorded and regulatory developments.



/s/ DELOITTE & TOUCHE LLP

Parsippany, New Jersey
February 24, 2022

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, 2021 and 2020, 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, 2021, 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, 2021 and 2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2021, 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 Matters

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.

Regulatory Assets and Liabilities – Income Taxes —Refer to Notes 1, 7, and 22 to the financial statements

Critical Audit Matter Description

PSE&G’s electric and gas transmission and distribution businesses are regulated by the Board of Public Utilities (BPU) and Federal Energy Regulatory Commission. 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 cost-based rate regulation. Through the rate-making process, PSE&G’s rates to customers also include the recovery of income tax expense associated with PSE&G’s electric and gas distribution and electric transmission operations. PSE&G has recorded regulatory liabilities for excess accumulated deferred income taxes (ADIT) which will be refunded to customers in future periods. PSE&G’s most recent electric and gas distribution base rate case, concluded in 2018, established the Tax Adjustment Credit (TAC) that provides for the refund of these excess ADIT regulatory liabilities as well as the flow through to customers of historical and current accumulated deferred income taxes for tax-deductible repairs. The flow through of the current tax benefits results in lower revenues and lower income tax expense, as well as the recognition of a regulatory asset as management believes it is probable that the accumulated tax benefits treated as a flow-through item to PSE&G customers will be recovered from customers in the future.

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How the Critical Audit Matter Was Addressed in the Audit

Our audit procedures to evaluate PSE&G’s accounting for the TAC and the associated regulatory assets, regulatory liabilities, and income tax expense included the following, among others:

• We tested the effectiveness of controls over the calculation of the amounts refunded through the TAC, including controls over the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering the TAC regulatory asset in future rates.

• We evaluated management’s analysis over the assertion that the TAC regulatory assets are probable of recovery.

• We evaluated relevant regulatory orders related to the ratemaking treatment of income taxes.

• With the assistance of our income tax specialists, we tested the accuracy of income tax expense, regulatory assets and regulatory liabilities associated with the TAC.

• We evaluated the financial statement presentation and disclosures related to TAC, including the balances recorded and regulatory developments.



/s/ DELOITTE & TOUCHE LLP

Parsippany, New Jersey
February 24, 2022

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,
	2021		2020		2019
OPERATING REVENUES	$	9,722	$	9,603	$	10,076
OPERATING EXPENSES
Energy Costs	3,499		3,056		3,372
Operation and Maintenance	3,226		3,115		3,111
Depreciation and Amortization	1,216		1,285		1,248
(Gains) Losses on Asset Dispositions and Impairments	2,637		(123)		402
Total Operating Expenses	10,578		7,333		8,133
OPERATING INCOME (LOSS)	(856)		2,270		1,943
Income from Equity Method Investments	16		14		14
Net Gains (Losses) on Trust Investments	194		253		260
Other Income (Deductions)	98		115		125
Net Non-Operating Pension and Other Postretirement Benefit (OPEB) Credits (Costs)	328		249		177
Loss on Extinguishment of Debt	(298)		—		—
Interest Expense	(571)		(600)		(569)
INCOME (LOSS) BEFORE INCOME TAXES	(1,089)		2,301		1,950
Income Tax Benefit (Expense)	441		(396)		(257)
NET INCOME (LOSS)	$	(648)	$	1,905	$	1,693
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:
BASIC	504		504		504
DILUTED	504		507		507
NET INCOME (LOSS) PER SHARE:
BASIC	$	(1.29)	$	3.78	$	3.35
DILUTED	$	(1.29)	$	3.76	$	3.33

See Notes to Consolidated Financial Statements.

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PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

Millions



	Years Ended December 31,
		2021		2020		2019
NET INCOME (LOSS)		$	(648)	$	1,905	$	1,693
Other Comprehensive Income (Loss), net of tax
Unrealized Gains (Losses) on Available-for-Sale Securities, net of tax (expense) benefit of $25, $(16) and $(26) for the years ended 2021, 2020 and 2019, respectively		(39)		25		41
Unrealized Gains (Losses) on Cash Flow Hedges, net of tax (expense) benefit of $(1), $(2) and $6 for the years ended 2021, 2020 and 2019, respectively		3		6		(14)
Pension/OPEB adjustment, net of tax (expense) benefit of $(75), $18 and $18 for the years ended 2021, 2020 and 2019, respectively		190		(46)		(58)
Other Comprehensive Income (Loss), net of tax		154		(15)		(31)
COMPREHENSIVE INCOME (LOSS)		$	(494)	$	1,890	$	1,662

See Notes to Consolidated Financial Statements.

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PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

CONSOLIDATED BALANCE SHEETS

Millions



	December 31,
	2021		2020
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents	$	818	$	543
Accounts Receivable, net of allowance of $325 in 2021 and $196 in 2020	1,859		1,410
Tax Receivable	9		63
Unbilled Revenues, net of allowance of $12 in 2021 and $10 in 2020	217		229
Fuel	296		277
Materials and Supplies, net	448		601
Prepayments	63		51
Derivative Contracts	72		60

Regulatory Assets	364		369
Assets Held for Sale	2,060		—
Other	44		27
Total Current Assets	6,250		3,630
PROPERTY, PLANT AND EQUIPMENT	43,684		48,569
Less: Accumulated Depreciation and Amortization	(9,318)		(10,984)
Net Property, Plant and Equipment	34,366		37,585
NONCURRENT ASSETS
Regulatory Assets	3,605		3,872
Operating Lease Right-of-Use Assets	201		262
Long-Term Investments	541		536
Nuclear Decommissioning Trust (NDT) Fund	2,637		2,501
Long-Term Tax Receivable	47		—
Long-Term Receivable of Variable Interest Entity	828		945
Rabbi Trust Fund	242		266
Intangibles	20		158
Derivative Contracts	28		9
Other	234		286
Total Noncurrent Assets	8,383		8,835
TOTAL ASSETS	$	48,999	$	50,050

See Notes to Consolidated Financial Statements.

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PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

CONSOLIDATED BALANCE SHEETS

Millions



	December 31,
	2021		2020
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES
Long-Term Debt Due Within One Year	$	700	$	1,684
Commercial Paper and Loans	3,519		1,063
Accounts Payable	1,315		1,332
Derivative Contracts	17		21
Accrued Interest	121		126
Accrued Taxes	67		124
Clean Energy Program	146		143
Obligation to Return Cash Collateral	179		98
Regulatory Liabilities	388		294
Liabilities Held for Sale	144		—
Other	476		637
Total Current Liabilities	7,072		5,522
NONCURRENT LIABILITIES
Deferred Income Taxes and Investment Tax Credits (ITC)	5,759		6,502
Regulatory Liabilities	2,497		2,707
Operating Leases	191		252
Asset Retirement Obligations	1,573		1,212
Other Postretirement Benefit (OPEB) Costs	572		730
OPEB Costs of Servco	640		699
Accrued Pension Costs	318		1,128
Accrued Pension Costs of Servco	174		226

Environmental Costs	245		286
Derivative Contracts	17		4
Long-Term Accrued Taxes	100		88
Other	184		214
Total Noncurrent Liabilities	12,270		14,048
COMMITMENTS AND CONTINGENT LIABILITIES (See Note 15)
CAPITALIZATION
LONG-TERM DEBT	15,219		14,496
STOCKHOLDERS’ EQUITY
Common Stock, no par, authorized 1,000 shares; issued, 2021 and 2020—534 shares	5,045		5,031
Treasury Stock, at cost, 2021 and 2020—30 shares	(896)		(861)
Retained Earnings	10,639		12,318
Accumulated Other Comprehensive Loss	(350)		(504)


Total Stockholders’ Equity	14,438		15,984
Total Capitalization	29,657		30,480
TOTAL LIABILITIES AND CAPITALIZATION	$	48,999	$	50,050

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,
	2021		2020		2019
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income (Loss)	$	(648)	$	1,905	$	1,693
Adjustments to Reconcile Net Income (Loss) to Net Cash Flows from Operating Activities:
Depreciation and Amortization	1,216		1,285		1,248
Amortization of Nuclear Fuel	187		184		178
(Gains) Losses on Asset Dispositions and Impairments	2,637		(123)		402
Loss on Extinguishment of Debt	298		—		—
Emission Allowances and Renewable Energy Credit (REC) Compliance Accrual	138		151		108
Provision for Deferred Income Taxes (Other than Leases) and ITC	(817)		139		180
Non-Cash Employee Benefit Plan (Credits) Costs	(178)		(105)		(48)
Leveraged Lease (Income), (Gains) and Losses, Adjusted for Rents Received and Deferred Taxes	(11)		(135)		18
Net Realized and Unrealized (Gains) Losses on Energy Contracts and Other Derivatives	614		80		(290)
Cost of Removal	(121)		(106)		(108)
Net Change in Regulatory Assets and Liabilities	(271)		(101)		25
Net (Gains) Losses and (Income) Expense from NDT Fund	(229)		(278)		(296)
Net Change in Certain Current Assets and Liabilities:
Tax Receivable	56		107		77
Accrued Taxes	(127)		124		(9)
Cash Collateral	(790)		(10)		349
Other Current Assets and Liabilities	(238)		73		(145)
Employee Benefit Plan Funding and Related Payments	(25)		(18)		(39)
Other	45		(70)		36
Net Cash Provided By (Used In) Operating Activities	1,736		3,102		3,379
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment	(2,719)		(2,923)		(3,166)
Purchase of Emissions Allowances and RECs	(98)		(111)		(98)
Proceeds from Sales of Trust Investments	2,100		2,234		1,787
Purchases of Trust Investments	(2,092)		(2,250)		(1,814)
Proceeds from Sales of Long-Lived Assets and Lease Investments	569		301		70
Contributions to Equity Method Investments	(111)		—		—
Other	107		73		76
Net Cash Provided By (Used In) Investing Activities	(2,244)		(2,676)		(3,145)
CASH FLOWS FROM FINANCING ACTIVITIES
Net Change in Commercial Paper	256		(352)		99
Proceeds from Short-Term Loans	2,500		800		—
Repayment of Short-Term Loans	(300)		(500)		—
Issuance of Long-Term Debt	2,825		2,450		1,900
Redemption of Long-Term Debt	(3,082)		(1,365)		(1,250)
Premium Paid on Early Extinguishment of Debt	(294)		—		—
Cash Dividends Paid on Common Stock	(1,031)		(991)		(950)
Other	(75)		(72)		(56)
Net Cash Provided By (Used In) Financing Activities	799		(30)		(257)
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash	291		396		(23)
Cash, Cash Equivalents and Restricted Cash at Beginning of Period	572		176		199
Cash, Cash Equivalents and Restricted Cash at End of Period	$	863	$	572	$	176
Supplemental Disclosure of Cash Flow Information:
Income Taxes Paid (Received)	$	425	$	297	$	41
Interest Paid, Net of Amounts Capitalized	$	547	$	568	$	539
Accrued Property, Plant and Equipment Expenditures	$	331	$	387	$	499

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, 2018	534	$	4,980	(30)	$	(808)	$	10,582	$	(377)	$	14,377
Net Income	—	—		—	—		1,693		—		1,693
Cumulative Effect Adjustment to Reclassify Stranded Tax Effects Resulting in the Change in the Federal Corporate Income Tax Rate	—	—		—	—		81		(81)		—
Other Comprehensive Income (Loss), net of tax (expense) benefit of $(2)	—	—		—	—		—		(31)		(31)
Comprehensive Income											1,662
Cash Dividends at $1.88 per share on Common Stock	—	—		—	—		(950)		—		(950)
Other	—	23		—	(23)		—		—		—
Balance as of December 31, 2019	534	$	5,003	(30)	$	(831)	$	11,406	$	(489)	$	15,089
Net Income	—	—		—	—		1,905		—		1,905
Other Comprehensive Income (Loss), net of tax (expense) benefit of $0	—	—		—	—		—		(15)		(15)
Comprehensive Income											1,890
Cumulative Effect Adjustment for Current Expected Credit Losses (CECL)	—	—		—	—		(2)		—		(2)
Cash Dividends at $1.96 per share on Common Stock	—	—		—	—		(991)		—		(991)
Other	—	28		—	(30)		—		—		(2)
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

See Notes to Consolidated Financial Statements.

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PUBLIC SERVICE ELECTRIC AND GAS COMPANY

CONSOLIDATED STATEMENTS OF OPERATIONS

Millions



	Years Ended December 31,
	2021		2020		2019
OPERATING REVENUES	$	7,122	$	6,608	$	6,625
OPERATING EXPENSES
Energy Costs	2,688		2,469		2,738
Operation and Maintenance	1,692		1,614		1,581
Depreciation and Amortization	928		887		837
Gain on Asset Dispositions	(4)		(1)		—
Total Operating Expenses	5,304		4,969		5,156
OPERATING INCOME	1,818		1,639		1,469
Net Gains (Losses) on Trust Investments	2		3		2
Other Income (Deductions)	88		108		83
Non-Operating Pension and OPEB Credits (Costs)	264		205		150
Interest Expense	(402)		(388)		(361)
INCOME BEFORE INCOME TAXES	1,770		1,567		1,343
Income Tax Benefit (Expense)	(324)		(240)		(93)
NET INCOME	$	1,446	$	1,327	$	1,250

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

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PUBLIC SERVICE ELECTRIC AND GAS COMPANY

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

Millions



	Years Ended December 31,
		2021		2020		2019
NET INCOME		$	1,446	$	1,327	$	1,250
Other Comprehensive Income (Loss), net of tax
Unrealized Gains (Losses) on Available-for-Sale Securities, net of tax (expense) benefit of $1, $0 and $(1) for the years ended 2021, 2020 and 2019, respectively		(2)		1		3
COMPREHENSIVE INCOME		$	1,444	$	1,328	$	1,253

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

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PUBLIC SERVICE ELECTRIC AND GAS COMPANY

CONSOLIDATED BALANCE SHEETS

Millions



	December 31,
	2021		2020
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents	$	294	$	204
Accounts Receivable, net of allowance of $325 in 2021 and $196 in 2020	1,050		1,004


Unbilled Revenues, net of allowance of $12 in 2021 and $10 in 2020	217		229
Materials and Supplies, net	233		217
Prepayments	15		14
Regulatory Assets	364		369




Other	33		13
Total Current Assets	2,206		2,050
PROPERTY, PLANT AND EQUIPMENT	38,588		36,300
Less: Accumulated Depreciation and Amortization	(7,640)		(7,149)
Net Property, Plant and Equipment	30,948		29,151
NONCURRENT ASSETS
Regulatory Assets	3,605		3,872
Operating Lease Right-of-Use Assets	92		99
Long-Term Investments	181		222
Rabbi Trust Fund	43		51


Other	123		136
Total Noncurrent Assets	4,044		4,380
TOTAL ASSETS	$	37,198	$	35,581

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

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PUBLIC SERVICE ELECTRIC AND GAS COMPANY

CONSOLIDATED BALANCE SHEETS

Millions



	December 31,
	2021		2020
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES
Long-Term Debt Due Within One Year	$	—	$	434
Commercial Paper and Loans	—		100
Accounts Payable	571		671

Accounts Payable—Affiliated Companies	418		479
Accrued Interest	107		101
Clean Energy Program	146		143

Obligation to Return Cash Collateral	179		98
Regulatory Liabilities	388		294
Other	376		530
Total Current Liabilities	2,185		2,850
NONCURRENT LIABILITIES
Deferred Income Taxes and ITC	4,874		4,524
Regulatory Liabilities	2,497		2,707
Operating Leases	83		88
Asset Retirement Obligations	363		314
OPEB Costs	354		485
Accrued Pension Costs	132		612


Environmental Costs	191		236

Long-Term Accrued Taxes	6		7
Other	145		154
Total Noncurrent Liabilities	8,645		9,127
COMMITMENTS AND CONTINGENT LIABILITIES (See Note 15)
CAPITALIZATION
LONG-TERM DEBT	11,795		10,475
STOCKHOLDER’S EQUITY
Common Stock; 150 shares authorized; issued and outstanding, 2021 and 2020—132 shares	892		892
Contributed Capital	1,170		1,170
Basis Adjustment	986		986
Retained Earnings	11,524		10,078
Accumulated Other Comprehensive Income	1		3
Total Stockholder’s Equity	14,573		13,129
Total Capitalization	26,368		23,604
TOTAL LIABILITIES AND CAPITALIZATION	$	37,198	$	35,581

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

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PUBLIC SERVICE ELECTRIC AND GAS COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

Millions



	Years Ended December 31,
	2021		2020		2019
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	1,446	$	1,327	$	1,250
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	928		887		837

Provision for Deferred Income Taxes and ITC	116		53		(28)
Non-Cash Employee Benefit Plan (Credits) Costs	(156)		(103)		(62)
Cost of Removal	(121)		(106)		(108)
Net Change in Other Regulatory Assets and Liabilities	(271)		(101)		25
Net Change in Certain Current Assets and Liabilities
Accounts Receivable and Unbilled Revenues	(34)		(100)		(18)
Materials and Supplies	(16)		(2)		(14)
Prepayments	(1)		21		(9)
Accounts Payable	(71)		44		(59)
Accounts Receivable/Payable—Affiliated Companies, net	(32)		80		203
Other Current Assets and Liabilities	10		60		62
Employee Benefit Plan Funding and Related Payments	(10)		(4)		(21)
Other	(64)		(103)		(23)
Net Cash Provided By (Used In) Operating Activities	1,724		1,953		2,035
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment	(2,447)		(2,507)		(2,542)
Proceeds from Sales of Trust Investments	35		40		36
Purchases of Trust Investments	(29)		(40)		(34)
Solar Loan Investments	29		13		8
Other	16		12		10
Net Cash Provided By (Used In) Investing Activities	(2,396)		(2,482)		(2,522)
CASH FLOWS FROM FINANCING ACTIVITIES
Net Change in Commercial Paper and Loans	(100)		(262)		90
Issuance of Long-Term Debt	1,325		1,350		1,150
Redemption of Long-Term Debt	(434)		(259)		(500)
Contributed Capital	—		75		—
Cash Dividend Paid	—		(175)		(250)
Other	(13)		(17)		(14)
Net Cash Provided By (Used In) Financing Activities	778		712		476
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash	106		183		(11)
Cash, Cash Equivalents and Restricted Cash at Beginning of Period	233		50		61
Cash, Cash Equivalents and Restricted Cash at End of Period	$	339	$	233	$	50
Supplemental Disclosure of Cash Flow Information:
Income Taxes Paid (Received)	$	266	$	157	$	(48)
Interest Paid, Net of Amounts Capitalized	$	383	$	369	$	343
Accrued Property, Plant and Equipment Expenditures	$	294	$	323	$	335

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

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PUBLIC SERVICE ELECTRIC AND GAS COMPANY

CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER’S EQUITY

Millions



	Common Stock		Contributed Capital		Basis Adjustment		Retained Earnings		Accumulated Other Comprehensive Income (Loss)		Total
Balance as of December 31, 2018	$	892	$	1,095	$	986	$	7,928	$	(1)	$	10,900
Net Income	—		—		—		1,250		—		1,250
Other Comprehensive Income (Loss), net of tax (expense) benefit of $(1)	—		—		—		—		3		3
Comprehensive Income											1,253
Cash Dividends Paid	—		—		—		(250)		—		(250)
Balance as of December 31, 2019	$	892	$	1,095	$	986	$	8,928	$	2	$	11,903
Net Income	—		—		—		1,327		—		1,327
Other Comprehensive Income (Loss), net of tax (expense) benefit of $0	—		—		—		—		1		1
Comprehensive Income											1,328
Cumulative Effect Adjustment for CECL	—		—		—		(2)		—		(2)
Cash Dividends Paid	—		—		—		(175)		—		(175)
Contributed Capital	—		75		—		—		—		75
Balance as of December 31, 2020	$	892	$	1,170	$	986	$	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	$	1,170	$	986	$	11,524	$	1	$	14,573

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

Public Service Enterprise Group Incorporated (PSEG) is a holding company with a diversified business mix within the energy industry. Its operations are primarily in the Northeastern and Mid-Atlantic United States and in other select markets. PSEG’s two reportable segments, our principal direct wholly owned 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) and the Federal Energy Regulatory Commission (FERC). PSE&G also invests in regulated solar generation projects and energy efficiency and related programs in New Jersey, which are regulated by the BPU.

•PSEG Power LLC (PSEG Power)—which is a multi-regional energy supply company that integrates the operations of its merchant nuclear and fossil generating assets with its fuel supply functions through competitive energy sales in well-developed energy markets primarily in the Northeast and Mid-Atlantic United States through its principal direct wholly owned subsidiaries. PSEG Power’s subsidiaries are subject to regulation by FERC, the Nuclear Regulatory Commission (NRC), the Environmental Protection Agency (EPA) and the states in which they operate.

PSEG’s other direct wholly owned subsidiaries are: PSEG Energy Holdings L.L.C. (Energy Holdings), which holds our investments in offshore wind ventures and legacy portfolio of lease investments; PSEG Long Island LLC (PSEG LI), which operates the Long Island Power Authority’s (LIPA) electric transmission and distribution (T&D) system under an Operations Services Agreement (OSA); 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).

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 5. Variable Interest Entities. 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. For investments in which significant influence does not exist and the investor is not the primary beneficiary, the cost method of accounting is applied. 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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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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 7. Regulatory Assets and Liabilities.

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, 2020 and 2021. Restricted cash consists primarily of deposits received related to various construction projects at PSE&G.



	PSE&G		Other (A)		Consolidated
	Millions
As of December 31, 2020
Cash and Cash Equivalents	$	204	$	339	$	543
Restricted Cash in Other Current Assets	7		—		7
Restricted Cash in Other Noncurrent Assets	22		—		22
Cash, Cash Equivalents and Restricted Cash	$	233	$	339	$	572
As of December 31, 2021
Cash and Cash Equivalents	$	294	$	524	$	818
Restricted Cash in Other Current Assets	28		—		28
Restricted Cash in Other Noncurrent Assets	17		—		17
Cash, Cash Equivalents and Restricted Cash	$	339	$	524	$	863

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

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, fossil fuels and other commodities. Fluctuations in market prices result from changes in supply and demand, fuel costs, market conditions, weather, state and federal regulatory policies, environmental policies, transmission availability and other factors. PSEG Power uses a variety of derivative and non-derivative instruments, such as financial options, futures, swaps, fuel purchases and forward purchases and sales of electricity, to manage the exposure to fluctuations in commodity prices and optimize the value of PSEG Power’s expected generation. 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 are 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. For fair value hedges, changes in fair values for both the derivative and the underlying hedged exposure are recognized in earnings each period.

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.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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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 fair value or cash flow hedge accounting on its commodity derivative positions.

Contracts that qualify for, and are designated, as NPNS are accounted for upon settlement. Contracts which qualify for NPNS are contracts for which physical delivery is probable, they will not be financially settled, and the quantities under contract are expected to be used or sold in the normal course of business over a reasonable period of time.

For additional information regarding derivative financial instruments, see Note 18. 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 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.

The majority of PSEG Power’s revenues 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 that are not designated as NPNS. See Note 18. Financial Risk Management Activities for further discussion.

PJM Interconnection, L.L.C. (PJM), the Independent System Operator-New England (ISO-NE) and the New York Independent System Operator (NYISO) facilitate the dispatch of energy and energy-related products. PSEG generally reports electricity sales and purchases conducted with those individual Independent System Operators (ISOs) 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 the individual ISOs.

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 5. Variable Interest Entities for further information.

For additional information regarding Revenues, see Note 3. Revenues.

Depreciation and Amortization (D&A)

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:



	2021		2020		2019
	Avg Rate		Avg Rate		Avg Rate
Electric Transmission	2.29	%	2.41	%	2.41	%
Electric Distribution	2.56	%	2.55	%	2.54	%
Gas Distribution	1.84	%	1.84	%	1.85	%

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.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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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, 2021, 2020 and 2019 were as follows:



	AFUDC/IDC Capitalized
	2021				2020				2019
	Millions		Avg Rate		Millions		Avg Rate		Millions		Avg Rate
PSE&G	$	93	7.37	%	$	112	7.86	%	$	81	7.22	%
Other	$	9	4.90	%	$	10	4.60	%	$	27	4.60	%

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 separate return 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 deferred in prior years are being amortized over the useful lives of the related property.

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 22. Income Taxes for further discussion.

Impairment of Long-Lived Assets and Leveraged Leases

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.

Energy Holdings’ leveraged leases are comprised of Lease Receivables (net of non-recourse debt), the estimated residual value of leased assets, and unearned and deferred income. Residual values are the estimated values of the leased assets at the end of the respective lease per the original lease terms, net of any subsequent impairments. A review of the residual valuations, which are calculated by discounting the cash flows related to the leased assets after the lease term, is performed at least annually for each asset subject to lease using specific assumptions tailored to each asset. Those valuations are compared to the recorded residual values to determine if an impairment is warranted.

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 ongoing coronavirus pandemic on the

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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outstanding balances as of December 31, 2021. 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 COVID-19 Regulatory Asset. See Note 3. Revenues and Note 7. 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 includes stored natural gas and propane used to generate power and to satisfy obligations under PSEG Power’s gas supply contracts with PSE&G. As of December 31, 2021, all of PSEG Power’s fuel oil was classified as Held for Sale. See Note 4. Early Plant Retirements/Asset Dispositions and Impairments for additional information. 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 spares are depreciated over the remaining lives of their associated assets.

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.

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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, real estate assets and land. PSEG and subsidiaries account for the lease and non-lease components as a single lease component. See Note 8. 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 9. Long-Term Investments and Note 10. 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 11. 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 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 14. Pension and 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.

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.

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Note 2. Recent Accounting Standards

New Standards Adopted in 2021

Simplifying the Accounting for Income Taxes—Accounting Standards Update (ASU) 2019-12

This accounting standard updates Accounting Standards Codification (ASC) 740 to simplify the accounting for income taxes, including the elimination of several exceptions and making other clarifications to the current guidance. Some of the more pertinent modifications include a change to the tax accounting related to franchise taxes that are partially based on income, an election to allocate the consolidated tax expense to a disregarded entity that is a member of a consolidated tax return filing group when those entities issue separate financial statements, and modifications and clarifications to interim tax reporting.

The standard is effective for fiscal years beginning after December 15, 2020. PSEG adopted this standard on January 1, 2021. PSEG has elected to allocate the consolidated tax expense to all eligible entities that are included in a consolidated tax filing on a prospective basis. This election is consistent with PSEG’s Tax Sharing Agreements with its affiliated subsidiaries. Adoption of this standard did not have an impact on the financial statements of PSEG and PSE&G.

Clarifying the Interactions between Investments-Equity Securities, Investments-Equity Method and Joint Ventures, and Derivatives and Hedging—ASU 2020-01

This accounting standard clarifies that an entity should consider transaction prices for purposes of measuring the fair value of certain equity securities immediately before applying or upon discontinuing the equity method. This accounting standard also clarifies that when accounting for contracts entered into to purchase equity securities, an entity should not consider whether, upon the settlement of the forward contract or exercise of the purchased option, the underlying securities would be accounted for under the equity method or the fair value option.

The standard is effective for fiscal years beginning after December 15, 2020. PSEG adopted this standard prospectively on January 1, 2021. Adoption of this standard did not have an impact on the financial statements of PSEG and PSE&G.

Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity—ASU 2020-06

This accounting standard simplifies the accounting for convertible debt and convertible preferred stock by removing the requirements to separately present certain conversion features in equity. In addition, the ASU eliminates certain criteria that must be satisfied in order to classify a contract as equity, which is expected to decrease the number of freestanding instruments and embedded derivatives accounted for as assets or liabilities. The ASU also revises the guidance on calculating earnings per share, requiring use of the if-converted method for all convertible instruments and rescinding the ability to rebut the presumption of share settlement for instruments that may be settled in cash or other assets.

The standard is effective for fiscal years beginning after December 15, 2021. PSEG early adopted this standard on January 1, 2021 on a modified retrospective basis. Adoption of this standard did not have an impact on the financial statements of PSEG and PSE&G.

Codification Improvements to Callable Debt Securities—ASU 2020-08

This accounting standard clarifies that an entity should reevaluate for each reporting period whether a purchased callable debt security that has multiple call dates is within the scope of certain guidance on nonrefundable fees and other costs related to receivables.

Codification Improvements—ASU 2020-10

This accounting standard conforms, clarifies, simplifies, and provides technical corrections to various codification topics.

The standard is effective for fiscal years beginning after December 15, 2020. PSEG adopted this standard on January 1, 2021. Adoption of this standard did not have an impact on the financial statements of PSEG and PSE&G.

Reference Rate Reform Scope Refinement—ASU 2021-01

This accounting standard clarifies certain guidance related to derivative instruments affected by the market-wide change in the interest rates even if those derivatives do not reference the LIBOR or another rate that is expected to be discontinued as a result of reference rate reform. The accounting standard also clarifies other aspects of the relief provided in the reference rate reform GAAP guidance.

The standard is effective upon issuance and allows for retrospective or prospective application with certain conditions. PSEG adopted this standard prospectively in January 2021. Adoption of this standard did not have an impact on the financial statements of PSEG and PSE&G.

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New Standards Issued But Not Yet Adopted as of December 31, 2021

Issuer’s Accounting for Certain Modifications or Exchanges of Freestanding Equity-Classified Written Call Options—ASU 2021-04

This accounting standard clarifies an issuer’s accounting for certain modifications or exchanges of freestanding equity-classified written call options that remain equity-classified after modification or exchange. It provides guidance on how an issuer would determine whether it should recognize the modification or exchange as an adjustment to equity or an expense.

The standard is effective for fiscal years beginning after December 15, 2021. PSEG adopted this standard prospectively on January 1, 2022. Adoption of this standard did not have an impact on the financial statements of PSEG and PSE&G.

Lessors-Certain Leases with Variable Lease Payments—ASU 2021-05

This accounting standard improves an area of the lease guidance related to a lessor’s accounting for certain leases with variable lease payments. It amends the lessor lease classification requirements and, as a result, a lessor is now required to classify and account for a lease with variable payments as an operating lease if (i) the lease would have been classified as a sales-type lease or a direct financing lease and (ii) the lessor would have otherwise recognized a day-one loss. A day-one loss or profit is not recognized under operating lease accounting.

Business Combinations – Accounting for Contract Assets and Contract Liabilities from Contracts with Customers—ASU 2021-08

This accounting standard amends the business combination guidance by requiring entities to apply the revenue recognition standard to recognize and measure contract assets and contract liabilities in a business combination.

The standard is effective for fiscal years beginning after December 15, 2022 and early adoption is permitted. Amendments in this standard will be applied prospectively to business combinations occurring on or after the effective date of the amendments. PSEG is currently analyzing the impact of this standard on its financial statements.

Government Assistance – Disclosures by Business Entities about Government Assistance—ASU 2021-10

This accounting standard increases transparency in financial reporting by requiring business entities to disclose, in notes to financial statements, certain information when they (i) have received government assistance and (ii) use a grant or contribution accounting model by analogy to other accounting guidance.

Note 3. Revenues

Nature of Goods and Services

The following is a description of principal activities by reportable segment from which PSEG and PSE&G 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 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.

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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.

Payment for services rendered and products transferred are typically due on average within 30 days of delivery.

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), weather normalization, green energy program true-ups and transmission formula rate true-ups, are not a material source of PSE&G revenues.

Other

Revenues from Contracts with Customers

Electricity and Related Products—Wholesale load contracts have been executed in the different ISO regions for the bundled supply of energy, capacity, renewable energy credits (RECs) and ancillary services representing PSEG Power’s performance obligations. Revenue for these contracts is recognized over time as the bundled service is provided to the customer. Transaction terms generally run from several months to three years. PSEG Power also sells to the ISOs energy and ancillary services which are separately transacted in the day-ahead or real-time energy markets. The energy and ancillary services performance obligations are typically satisfied over time as delivered and revenue is recognized accordingly. PSEG generally reports electricity sales and purchases conducted with those individual ISOs 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 the ISOs. The transactions are reported on a net basis dependent on PSEG Power’s monthly net sale or purchase position through the individual ISOs. The performance obligations with the ISOs are satisfied over time upon delivery of the capacity and revenue is recognized accordingly. In addition to capacity sold through the ISOs, PSEG Power sells capacity through bilateral contracts and the related revenue is reported on a gross basis and recognized over time upon delivery of the capacity.

In April 2019, PSEG Power’s Salem 1, Salem 2 and Hope Creek nuclear plants were awarded Zero Emission Certificates (ZECs) by the BPU. These nuclear plants are expected to receive ZEC revenue for approximately three years, through May 2022, from the electric distribution companies (EDCs) in New Jersey. In April 2021, PSEG Power’s Salem 1, Salem 2 and Hope Creek nuclear plants were awarded ZECs by the BPU for the three year eligibility period starting June 2022. PSEG Power recognizes revenue when the units generate electricity, which is when the performance obligation is satisfied. These revenues are included in PJM Sales in the following tables. See Note 4. Early Plant Retirements/Asset Dispositions and Impairments for additional information.

Gas Contracts—PSEG Power sells wholesale natural gas, primarily through an index based full-requirements Basic Gas Supply Service (BGSS) contract with PSE&G to meet the gas supply requirements of PSE&G’s customers. The BGSS contract remains in effect unless terminated by either party with a two-year notice. The performance obligation is primarily delivery of gas which is satisfied over time. Revenue is recognized as gas is delivered. 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 under these contracts is satisfied over time upon delivery of the gas or capacity, and revenue is recognized accordingly.

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.

Other Revenues from Contracts with Customers

Prior to the sale of Solar Source in June 2021, PSEG Power entered into bilateral contracts to sell solar power and solar renewable energy certificates (SRECs) from its solar facilities. Contract terms ranged from 15 to 30 years. The performance obligations were generally solar power and SRECs which were transferred to customers upon generation. Revenue was recognized upon generation of the solar power. See Note 4. Early Plant Retirements/Asset Dispositions and Impairments.

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.

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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 18. Financial Risk Management Activities for further discussion. Prior to the sale of Solar Source, PSEG Power was also a party to solar contracts that qualified as leases and were accounted for in accordance with lease accounting guidance. See Note 4. Early Plant Retirements/Asset Dispositions and Impairments.

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

Disaggregation of Revenues



	PSE&G		Other		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 (A)	343		620		(3)		960
Total Revenues from Contracts with Customers	7,108		4,374		(1,167)		10,315
Revenues Unrelated to Contracts with Customers (B)	14		(607)		—		(593)
Total Operating Revenues	$	7,122	$	3,767	$	(1,167)	$	9,722



	PSE&G		Other		Eliminations		Consolidated
	Millions
Year Ended December 31, 2020
Revenues from Contracts with Customers
Electric Distribution	$	3,130	$	—	$	—	$	3,130
Gas Distribution	1,646		—		(12)		1,634
Transmission	1,485		—		—		1,485
Electricity and Related Product Sales
PJM
Third-Party Sales	—		1,551		—		1,551
Sales to Affiliates	—		447		(447)		—
NYISO	—		124		—		124
ISO-NE	—		126		—		126
Gas Sales
Third-Party Sales	—		83		—		83
Sales to Affiliates	—		771		(771)		—
Other Revenues from Contracts with Customers (A)	338		632		(4)		966
Total Revenues from Contracts with Customers	6,599		3,734		(1,234)		9,099
Revenues Unrelated to Contracts with Customers (B)	9		495		—		504
Total Operating Revenues	$	6,608	$	4,229	$	(1,234)	$	9,603

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	PSE&G		Other		Eliminations		Consolidated
	Millions
Year Ended December 31, 2019
Revenues from Contracts with Customers
Electric Distribution	$	3,224	$	—	$	—	$	3,224
Gas Distribution	1,870		—		(15)		1,855
Transmission	1,181		—		—		1,181
Electricity and Related Product Sales
PJM
Third-Party Sales	—		1,785		—		1,785
Sales to Affiliates	—		536		(536)		—
NYISO	—		143		—		143
ISO-NE	—		137		—		137
Gas Sales
Third-Party Sales	—		92		—		92
Sales to Affiliates	—		927		(927)		—
Other Revenues from Contracts with Customers (A)	284		612		(5)		891
Total Revenues from Contracts with Customers	6,559		4,232		(1,483)		9,308
Revenues Unrelated to Contracts with Customers (B)	66		702		—		768
Total Operating Revenues	$	6,625	$	4,934	$	(1,483)	$	10,076

(A)Includes primarily revenues from appliance repair services and the sale of SRECs at auction at PSE&G, PSEG Power’s solar power projects and energy management and fuel service contracts with LIPA and PSEG LI’s OSA with LIPA in Other.

(B)Includes primarily alternative revenues at PSE&G and derivative contracts and lease contracts in Other. For the years ended December 31, 2021, 2020 and 2019, Other includes losses of $9 million, $26 million and $58 million, respectively, related to Energy Holdings’ investments in leases. For additional information, see Note 9. Long-Term Investments.

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, 2021 and 2020. 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 21% and 14% of accounts receivable (including unbilled revenues) as of December 31, 2021 and 2020, 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 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 ongoing coronavirus pandemic (COVID-19) on the outstanding balances as of December 31, 2021. PSE&G’s electric bad debt expense is recoverable through its SBC mechanism. As of December 31, 2021, PSE&G deferred incremental gas bad debt expense for future regulatory recovery due to the impact of the ongoing pandemic. See Note 7. 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, 2021 and 2020.










	Years Ended December 31,
	2021		2020
	Millions
Balance at Beginning of Year	$	206	$	68	(A)
Utility Customer and Other Accounts
Provision	195		175
Write-offs, net of Recoveries of $17 million and $5 million	(64)		(37)
Balance at End of Year	$	337	$	206

(A)Includes an $8 million pre-tax increase upon adoption of ASU 2016-13.

Other

PSEG Power generally collects consideration upon satisfaction of performance obligations, and therefore, PSEG Power had no material contract balances as of December 31, 2021 and 2020.

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 wholesale load contracts and capacity sales which are executed in the different ISO regions. PSEG Power also sells energy and ancillary services 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, 2021 and 2020. 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, 2021 and 2020.

Remaining Performance Obligations under Fixed Consideration Contracts

PSEG Power and PSE&G primarily record 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:

Other

As previously stated, capacity transactions with ISOs are reported on a net basis dependent on PSEG Power’s monthly net sale or purchase position through the individual ISOs.

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 2022/2023 auction was held in June 2021 and the 2023/2024 auction will be held in June 2022. 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 Megawatt (MW)-Day	MW Cleared (A)
June 2021 to May 2022	$166	7,700
June 2022 to May 2023	$98	6,300

(A)Of the existing MWs cleared, an approximate average of 3,500 MWs were transferred with the sale of PSEG Power’s fossil generation portfolio in February 2022.

Capacity Payments from the ISO-NE Forward Capacity Market (FCM)—The FCM Auction is conducted annually three years in advance of the operating period. The table below includes PSEG Power’s cleared capacity in the FCM Auction for the Bridgeport Harbor Station 5 (BH5), which cleared the 2019/2020 auction at $231/MW-day or seven years, and the retirement of Bridgeport Harbor Station 3 effective May 31, 2021. PSEG Power expects to realize the following average capacity prices for capacity obligations to be satisfied resulting from the FCM Auctions which have been completed through May 2025 and the

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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seven-year rate lock for BH5 through May 2026:



Delivery Year	$ per MW-Day (A)	MW Cleared (B)
June 2021 to May 2022	$192	950
June 2022 to May 2023	$179	950
June 2023 to May 2024	$152	930
June 2024 to May 2025	$158	950
June 2025 to May 2026	$231	480

(A)Capacity cleared prices for BH5 through 2026 will be escalated based upon the Handy-Whitman Index. These adjustments are not included above.

(B)Of the existing MWs cleared, the majority of these MWs were transferred with the sale of PSEG Power’s fossil generation portfolio in February 2022.

Bilateral capacity contracts—Capacity obligations pursuant to contract terms through 2029 are anticipated to result in revenues totaling $109 million. Approximately $44 million of these revenues were transferred with the sale of PSEG Power’s fossil generation portfolio.

The LIPA OSA is a 12-year services contract ending in 2025 with annual fixed and incentive components. The fixed fee for the provision of services thereunder in 2022 is approximately $70 million and is updated each year based on the change in the Consumer Price Index (CPI). See Note 15. Commitments and Contingent Liabilities for information related to the status of an amended OSA.

Note 4. Early Plant Retirements/Asset Dispositions and Impairments

Nuclear

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

The award of ZECs attaches certain obligations, including an obligation to repay the ZECs in the event that a plant ceases operations during the period that it was awarded ZECs, subject to certain exceptions specified in the ZEC legislation. PSEG Power has and will continue to recognize revenue monthly as the nuclear plants generate electricity and satisfy their performance obligations. Further, the ZEC payment may be adjusted by the BPU at any time to offset environmental or fuel diversity payments that a selected nuclear plant may receive from another source. For instance, the New Jersey Division of Rate Counsel (New Jersey Rate Counsel), in written comments filed with the BPU, has advocated for the BPU to offset market benefits resulting from New Jersey’s rejoining the Regional Greenhouse Gas Initiative from the ZEC payment. PSEG intends to vigorously defend against these arguments. Due to its preliminary nature, PSEG cannot predict the outcome of this matter.

In May 2021, the New Jersey Rate Counsel filed an appeal with the New Jersey Appellate Division of the BPU’s April 2021 decision. PSEG cannot predict the outcome of this matter.

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necessary steps to cease to operate all of these plants and will incur associated costs and accounting charges. These may include, among other things, one-time impairment charges or accelerated D&A Expense on the remaining carrying value of the plants, potential penalties associated with the early termination of capacity obligations and fuel contracts, accelerated asset retirement costs, severance costs, environmental remediation costs and, in certain circumstances potential additional funding of the NDT Fund, which would result in a material adverse impact on PSEG’s results of operations.

Non-Nuclear

In July 2020, PSEG announced that it was exploring strategic alternatives for PSEG Power’s non-nuclear generating fleet, which included 6,750 MW of fossil generation located in New Jersey, Connecticut, New York and Maryland and, prior to the sale of Solar Source in June 2021, included a 467 MW Solar Source portfolio located in various states.

In May 2021, Power Ventures 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 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 investment tax credits (ITC) 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.

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 February 2022, PSEG completed the sale of this fossil generating portfolio.

As a result of the Board of Directors’ approval of the transactions, PSEG’s fossil generating assets and liabilities to be disposed were reclassified to Assets and Liabilities Held for Sale in August 2021, and accordingly, PSEG ceased recording depreciation expense for these assets. 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. See Note 16. Debt and Credit Facilities for more detail on the debt extinguishment.

Further adjustments may be 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 as defined in each agreement; therefore, any future impairment is not estimable as of December 31, 2021 but may be material. In January 2022, PSEG Power recorded an additional impairment of approximately $20 million.

As of December 31, 2021, PSEG Power’s fossil generation assets and liabilities Held for Sale, including anticipated working capital, were $2,060 million and $144 million, respectively, as follows:



			As of December 31, 2021
		Millions
Current Assets (A)			$	264
Property, Plant and Equipment			1,742
Noncurrent Assets			54
	Total Assets Held for Sale		$	2,060

Current Liabilities (B)			$	57
Noncurrent Liabilities (C)			87
	Total Liabilities Held for Sale		$	144

(A)Primarily includes Fuel, Materials and Supplies, Prepayments and Other Current Assets.

(B)Primarily includes Accounts Payable and Other Current Liabilities.

(C)Primarily includes Asset Retirement Obligations (AROs), Accrued Pension Costs and Other Noncurrent Liabilities.

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These Held for Sale balances represent all of the assets and liabilities expected to transfer to the buyer at closing. PSEG Power will retain ownership of certain assets and liabilities excluded from the transactions primarily related to obligations under certain environmental regulations, including possible remediation obligations under the New Jersey Industrial Site Recovery Act and the Connecticut Transfer Act. Fulfilling the requirements under these regulations will span multiple years and may require sampling of environmental media to understand the extent of any required remediation. The amounts for any such environmental remediation are not estimable, but may be material.

In September 2020, PSEG Power completed the sale of its ownership interest in the Yards Creek generation facility. PSEG Power recorded a pre-tax gain on disposition of approximately $122 million in the third quarter of 2020 as the sale price was greater than book value.

In September 2019, PSEG Power completed the sale of its ownership interests in the Keystone and Conemaugh generation plants and related assets and liabilities. PSEG Power recorded a pre-tax loss on disposition of approximately $400 million in the second quarter of 2019 as the sale price was less than book value.

Note 5. Variable Interest Entities (VIEs)

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 2021, 2020 and 2019, Servco recorded $511 million, $520 million and $490 million, respectively, of O&M costs, the full reimbursement of which was reflected in Operating Revenues. For transactions in which Servco acts as an agent for LIPA, it records revenues and the related expenses on a net basis, resulting in no impact on PSEG’s Consolidated Statement of Operations.

VIE for which PSEG is not the Primary Beneficiary

PSEG holds a 25% equity interest in Ocean Wind JV HoldCo, LLC (OWH), which holds the Ocean Wind project that is expected to achieve full commercial operation in 2025. For additional information, see Note 1. Organization, Basis of Presentation and Summary of Significant Accounting Policies. OWH is considered a VIE since its equity investments at risk are not sufficient to permit this entity to finance its activities without additional subordinated financial support. Since PSEG does not have voting control or the power to direct the activities of OWH that most significantly impact its economic performance, PSEG has determined that it is not the primary beneficiary and therefore will account for this investment under the equity method. As of December 31, 2021, PSEG’s carrying amount of its investment in OWH was $111 million, which is included in Long-Term Investments on PSEG’s Consolidated Balance Sheet. PSEG’s maximum exposure to loss is limited to the carrying amount of its investment and additional planned funding of approximately $250 million to support continued project development to its final investment decision.

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Note 6. Property, Plant and Equipment and Jointly-Owned Facilities

Information related to Property, Plant and Equipment as of December 31, 2021 and 2020 is detailed below:



	2021		2020
	Millions
PSE&G
Electric Transmission	$	15,544	$	14,075
Electric Distribution	10,223		9,622
Gas Distribution and Transmission	9,818		9,081
Construction Work in Progress	1,196		1,783
Other	1,807		1,739
Total PSE&G	38,588		36,300
Nuclear Production	3,656		3,296
Nuclear Fuel in Service	762		748
Fossil Production	—		6,581
Construction Work in Progress	177		248
Other	501		1,396
Total	$	43,684	$	48,569

The above table excludes amounts as of December 31, 2021 which have been classified as Held for Sale. For additional information see Note 4. Early Plant Retirements/Asset Dispositions and Impairments.

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,
			2021				2020
	Ownership				Accumulated				Accumulated
	Interest		Plant		Depreciation		Plant		Depreciation
			Millions
PSE&G:
Transmission Facilities	Various		$	165	$	66	$	161	$	63
PSEG Power:
Nuclear Generating:
Peach Bottom	50	%	$	1,452	$	481	$	1,405	$	455
Salem	57	%	$	1,468	$	449	$	1,321	$	387
Nuclear Support Facilities	Various		$	226	$	107	$	226	$	97
Pumped Storage Facilities:
Merrill Creek Reservoir	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 Exelon Generation. PSEG Power is the operator of Salem and Exelon Generation 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.

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PSEG Power is a minority owner in the Merrill Creek Reservoir and Environmental Preserve in Warren County, New Jersey. Merrill Creek Owners Group is the owner-operator of this facility. The operator submits separate capital and O&M budgets, subject to PSEG Power’s approval as part of the normal PSEG Power governance process.

Note 7. Regulatory Assets and Liabilities

PSE&G prepares its financial statements in accordance with GAAP for regulated utilities as described in Note 1. Organization, Basis of Presentation and Summary of Significant Accounting Policies. PSE&G has deferred certain costs based on rate orders issued by the BPU or FERC or based on PSE&G’s experience with prior rate proceedings. Most of PSE&G’s Regulatory Assets and Liabilities as of December 31, 2021 are supported by written orders, either explicitly or implicitly through the BPU’s treatment of various cost items. These costs will be recovered and amortized over various future periods.

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

PSE&G had the following Regulatory Assets and Liabilities:



	As of December 31,
	2021		2020
	Millions
Regulatory Assets
Current
New Jersey Clean Energy Program	$	146	$	143
Electric Energy Costs—Basic Generation Service (BGS)	67		60
2018 Distribution Base Rate Case Regulatory Assets (BRC)	56		56
Tax Adjustment Credit (TAC)	44		—
Conservation Incentive Program (CIP)	36		—
Formula Rate True-up	13		23
SBC	—		82


Other	2		5
Total Current Regulatory Assets	364		369
Noncurrent
Deferred Income Tax Regulatory Assets	$	1,064	$	1,014
Pension and OPEB Costs	1,043		1,489
Manufactured Gas Plant (MGP) Remediation Costs	220		320
Green Program Recovery Charges (GPRC)	211		139
Asset Retirement Obligation	191		184
Electric Transmission and Gas Cost of Removal	174		189
Remediation Adjustment Charge (RAC) (Other SBC)	156		134
SBC (Electric Bad Debt)	139		—
COVID-19 Deferral	116		51
Deferred Storm Costs	109		99
BRC	47		103



Other	135		150
Total Noncurrent Regulatory Assets	3,605		3,872
Total Regulatory Assets	$	3,969	$	4,241

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	As of December 31,
	2021		2020
	Millions
Regulatory Liabilities
Current
Deferred Income Tax Regulatory Liabilities	$	288	$	250

Formula Rate True-up	42		—
GPRC	19		1
ZEC Liability	11		17
Gas Costs—BGSS	5		20


Other	23		6
Total Current Regulatory Liabilities	388		294
Noncurrent
Deferred Income Tax Regulatory Liabilities	$	2,443	$	2,670


Other	54		37
Total Noncurrent Regulatory Liabilities	2,497		2,707
Total Regulatory Liabilities	$	2,885	$	3,001

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

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

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

•CIP: The CIP reduces the impact on distribution revenues from changes in sales volumes and demand for most customers. The CIP, which is calculated annually, provides for a true-up of current period revenue as compared to revenue established in PSE&G’s most recent distribution base rate proceeding. Recovery under the CIP is subject to certain limitations, including an actual versus allowed return on equity (ROE) test and ceilings on customer rate increases. The CIP became effective in June 2021 for electric revenues and October 2021 for gas revenues. The gas CIP replaced the Weather Normalization Clause.

•COVID-19 Deferral: These amounts represent incremental costs related to COVID-19 as authorized for deferral in an order issued by the BPU to all New Jersey regulated utilities in July 2020. The BPU authorized such utilities to create a COVID-19-related Regulatory Asset by deferring on their books and records the prudently incurred incremental costs related to COVID-19 during the Regulatory Asset period, beginning on March 9, 2020 through September 30, 2021, or 60 days after the New Jersey governor determines that the Public Health Emergency is no longer in effect, or in the absence of such a determination, 60 days from the time the Public Health Emergency automatically terminates by law, whichever is later. Deferred costs are to be offset by any federal or state assistance that the utility may receive as a direct result of the COVID-19 pandemic. Utilities must file quarterly reports of the costs incurred and offsets. Each participating utility must file a petition documenting its prudently incurred incremental COVID-19 costs by December 31, 2021, or within 60 days of the close of the Regulatory Asset period as described above, whichever is later. In September 2021, the BPU extended the deferral period to December 31, 2022. Any potential rate recovery, including any prudency determinations and the appropriate period of recovery, will be addressed through that filing, or in the alternative, the utility may request that the BPU defer consideration of rate recovery for a future base rate case.

•Deferred Income Tax Regulatory Assets: These amounts relate to deferred income taxes arising from utility operations that have not been included in customer rates relating to depreciation, ITCs and other flow-through items, including the flowback to customers of accumulated deferred income taxes related to tax repair deductions. As part of its base rate case settlement with the BPU and the establishment of the TAC mechanism in 2018, PSE&G agreed to a ten-year flowback to customers of its accumulated deferred income taxes from previously realized tax repair

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deductions which resulted in the recognition of a $581 million Regulatory Asset and Regulatory Liability as of September 30, 2018. In addition, PSE&G agreed to the current flowback of tax benefits from ongoing tax repair deductions as realized which results in the recording of a Regulatory Asset upon flowback. For the years ended December 31, 2021, 2020 and 2019, PSE&G had provided $22 million, $31 million and $58 million, respectively, in current tax repair flowbacks to customers. The recovery and amortization of the tax repair-related Deferred Income Tax Regulatory Assets will be determined in PSE&G’s subsequent base rate cases.

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

•Unprotected distribution-related excess deferred income taxes are being refunded to customers over five years through PSE&G’s TAC mechanism as approved in its 2018 distribution base rate proceeding. As of December 31, 2021, the balance remaining to be flowed back to customers was approximately $371 million with the remaining flowback period through 2024.

•Protected distribution-related excess deferred income taxes are being refunded to customers over the remaining useful life of distribution property, plant and equipment through PSE&G’s TAC mechanism. As of December 31, 2021, the balance remaining to be flowed back to customers was approximately $905 million.

•Previously realized distribution-related tax repair deductions are being refunded to customers over ten years through PSE&G’s TAC mechanism. As of December 31, 2021, the balance remaining to be flowed back to customers was approximately $462 million through 2028.

•Protected transmission-related excess deferred income taxes are being refunded to customers over the remaining useful life of transmission property, plant and equipment through PSE&G’s transmission formula rate mechanism. As of December 31, 2021, the balance remaining to be flowed back to customers was approximately $939 million.

•Unprotected transmission-related deferred income taxes were fully refunded to customers in 2019 and 2020.

•Deferred Storm Costs: Incremental costs incurred in the restoration and related costs from major storms in 2019, 2020 and 2021 for which PSE&G will seek recovery in its next base rate proceeding.

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

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

•Formula Rate True-Up: PSE&G’s transmission revenues are earned under a FERC-approved annual formula rate mechanism which provides for an annual filing of an estimated revenue requirement with rates effective January 1 of each year and a true-up to that estimate based on actual revenue requirements.

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

•GPRC: This amount represents costs of the over or under collected balances associated with various Energy Efficiency and Renewable Energy (EE & RE) Programs. PSE&G files annually with the BPU for recovery of amounts that include a return on and of its investment over the lives of the underlying investments and capital assets which range from five to ten years. Interest is accrued monthly on any over or under recovered balances. Approved

100

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components of the GPRC include: Carbon Abatement, Energy Efficiency Economic Stimulus Program (EEE), EEE Extension Program, EEE Extension II Program, Solar Generation Investment Program (Solar 4 All®), Solar 4 All® Extension, Solar 4 All® Extension II, Solar Loan II Program, Solar Loan III Program, Energy Efficiency (EE) 2017 Program, Clean Energy Future–Energy Efficiency (CEF-EE), the Transition Renewable Energy Certificate (TRECs) Program and Clean Energy Act Studies (CEAS).

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

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

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

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

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

•TAC: This represents the over or under collected balances associated with the return of excess accumulated deferred income taxes and the flowback of previously realized and current tax repair deductions under a mechanism approved by the BPU in PSE&G’s 2018 Distribution Base Rate Case Settlement. Over or under collected balances are returned or recovered through an annual filing. PSE&G includes a return component on the flowback of the excess accumulated deferred income taxes and the previously realized tax repairs. Interest is accrued monthly on any over or under recovered balances.

•ZEC Liability: This represents amounts to be returned to customers for overcollections, including interest associated with the ZEC program whereby PSE&G purchases ZECs from eligible nuclear plants.

Significant 2021 regulatory orders received and currently pending rate filings with the BPU by PSE&G are as follows:

•BGS—In January 2022, the BPU approved changes to BGS rates as a result of the FERC-approved changes to transmission charges, primarily as a result of the decrease in PSE&G’s transmission formula rate ROE. PSE&G’s BGS customers will be credited over a 12-month period effective February 1, 2022.

•BGSS—In March 2021, the BPU gave final approval to PSE&G’s request to maintain the current BGSS rate of 32 cents per therm which had been provisionally approved effective October 1, 2020.

In June 2021, PSE&G made its annual BGSS filing with the BPU requesting to maintain the current BGSS rate of 32 cents and increase its BGSS Balancing Charge from 8.6 cents to 9.3 cents per therm which the BPU approved on a provisional basis in November 2021.

Under BGSS Orders issued by the BPU, New Jersey gas distribution companies (GDCs) may self-implement up to a 5% BGSS rate increase effective December 1 of the current year, and February 1 of the following year, with one month’s advance notice to the BPU and New Jersey Rate Counsel, and implement a decrease in its BGSS rate at any time during the year upon five days’ notice to the BPU and New Jersey Rate Counsel.

In November 2021, the BPU approved a waiver filed by PSE&G, along with other New Jersey GDCs, that allowed the GDCs to self-implement a BGSS increase of up to 5% effective December 1, 2021. As a result, PSE&G implemented a 5% increase resulting in a BGSS rate of 36 cents per therm, in addition to the provisionally approved increase in the BGSS Balancing Charge, both with effective dates of December 1, 2021. In December 2021, PSE&G gave notice of a second 5% self-implementing increase, effective February 1, 2022, resulting in a BGSS rate of 41 cents per therm.

•CEF-Energy Cloud (EC) or Advanced Metering Infrastructure (AMI) Initiative—In January 2021, the BPU approved PSE&G’s CEF-EC filing to spend $707 million in order to provide its 2.3 million electric customers with

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smart meters over the next four years. All of the capital and operating costs of the program will be recovered in PSE&G’s next base rate case, expected in the second half of 2024. From the start of the program until the commencement of new base rates, the return on and of the capital portion of the program will be included for recovery in those rates, as well as operating costs and stranded costs associated with the retirement of the existing meters.

•CEF-Electric Vehicles (EV)—In January 2021, the BPU approved a program for PSE&G to provide investments of approximately $166 million for EV charging infrastructure. All of the capital and operating costs of the program will be recovered in PSE&G’s next base rate case. From the start of the program until the commencement of new base rates, the return on and of the capital portion of the program will be included for recovery in those rates, as well as operating costs.

•Community Solar Energy Pilot (CSEP) Program, a New Component of the GPRC—In May 2021, PSE&G made its initial filing for recovery of costs related to the CSEP program. New Jersey’s Clean Energy Act provided for the establishment of a "Community Solar Energy Pilot Program” which permits electric customers to participate in a solar energy project that is remotely located from their properties but is within their electric public utility service territory. The program allows for a credit to the customer's utility bill equal to the electricity generated attributable to the customer's participation in the solar energy project. PSE&G’s filing proposes to recover an initial revenue requirement of $0.4 million associated with the CSEP Program as a new component of PSE&G’s existing electric Green Program Recovery Charge (GPRC). This matter is pending.

•CIP—In February 2022, PSE&G filed its initial electric CIP cost recovery petition seeking BPU approval to recover estimated deficient electric revenues of approximately $52 million. The filing is based on a twelve month period ending May 31, 2022, with actual results through November 2021 and forecasted amounts through May 2022. The revenue deficiency is the result of lower estimated revenues as compared to a baseline revenue calculated by utilizing approved determinants from PSE&G’s last base rate case applied to current distribution rates. Due to the savings test requirement also approved with the CIP filing, PSE&G expects to recover its $52 million request over two years. New rates are proposed to be effective June 1, 2022. This matter is pending.

•COVID-19 Deferral—PSE&G continues to make quarterly filings as required by the BPU and has recorded a Regulatory Asset as of December 31, 2021 of approximately $116 million for net incremental costs, including $64 million for incremental gas bad debt expense associated with customer accounts receivable, which PSE&G expects are probable of recovery under the BPU order. In September 2021, the BPU extended the period to December 31, 2022 during which incremental costs attributable to COVID-19 could be deferred as Regulatory Assets.

•Energy Strong (ES) II—In April 2021, the BPU approved PSE&G’s filing for a $13 million revenue increase under this investment program, effective May 2021. This increase represents the return on and of ES II electric investments placed in service through January 2021.

In November, 2021, PSE&G filed a petition seeking BPU approval to recover the annualized increases in electric and gas revenue requirements associated with capitalized investment costs of the ES II Program through January 31, 2022. In February 2022, the petition was updated to reflect the actual investments and costs, and requests annual electric and gas revenue increases of $15 million and $1 million, respectively, with rates effective no earlier than May 1, 2022. This matter is pending.

•GPRC—In June 2021, the BPU approved as final the GPRC rates approved by the BPU on a provisional basis in January 2021. In July 2021, PSE&G filed its 2021 GPRC cost recovery petition requesting BPU approval to recover a $2 million increase in each of electric and gas base rates annual revenues. This matter is pending.

•Gas System Modernization Program II (GSMP II)—In May 2021, the BPU approved PSE&G’s December 2020 cost recovery petition to recover in gas base rates an annual revenue increase of approximately $21 million effective June 1, 2021. This increase represents the return on and of GSMP II investments placed in service through February 2021.

In November 2021, the BPU approved PSE&G’s updated September 2021 GSMP II cost recovery petition to recover in gas base rates an annual revenue increase of approximately $28 million effective December 1, 2021. This increase represents the return on and of GSMP II investments in service through August 31, 2021.

In December 2021, PSE&G filed its next semiannual GSMP II cost recovery petition seeking BPU approval to recover in gas base rates an estimated annual revenue increase of approximately $27 million effective June 1, 2022.

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This increase represents the return on and of GSMP II investments placed in service through February 28, 2022. This request will be updated in March 2022 for actual costs.

•RAC—In July 2021, the BPU approved PSE&G’s RAC 28 filing requesting recovery of approximately $35 million in net MGP remediation expenditures incurred from August 1, 2019 through July 31, 2020.

•SBC—In August 2021, the BPU approved PSE&G’s 2020 SBC filing to recover electric and gas costs incurred under its EE & RE and Social Programs. The new rates reflect no change to the overall SBC rates to customers but allowed a decrease in the EE & RE sub-component to be added to the Social Programs rate. The remaining rate increase requested by PSE&G for recovery of its Social Programs costs associated with its electric bad debt costs was deferred to the next SBC filing. As of December 31, 2021, PSE&G had approximately $139 million in deferred electric bad debt costs.

In September 2021, the BPU approved the USF/Lifeline component of the SBC effective October 1, 2021, which provides for the recovery of costs provided to assist customers in paying their bills.

•Solar Successor Incentive (SuSi) Program, a New Component of the GPRC—In July 2021, the BPU approved an order establishing the SuSi Program as a replacement to the bridge Transition Renewable Energy Certificates program approved in 2019. In its SuSI Order, the BPU directed the New Jersey EDCs to engage a SuSI Administrator to acquire, on behalf of the EDCs, Solar Renewable Energy Certificate-IIs (SREC-IIs), produced by eligible solar generation projects, which will be funded through a SuSI charge to electric customers collected by the EDCs. The order allows the EDCs to recover their costs associated with the SuSI program in an annual filing, subject to approval by the BPU.

In December 2021, PSE&G filed for new rates of approximately $38 million for recovery of its expected share of SREC-II costs. PSE&G has requested that these costs be recovered as a new component of PSE&G’s existing electric GPRC, which is updated on an annual basis.

•TAC—In August 2021, the BPU approved PSE&G’s updated 2020 TAC filing which provides for changes in the TAC electric and gas credits, which will result in an annual decrease of approximately $22 million in electric revenues and an annual increase of approximately $57 million in gas revenues.

In October 2021, PSE&G made its annual 2021 TAC filing requesting BPU approval to reduce electric and gas revenues by approximately $15 million and $31 million, respectively, on an annual basis. This matter is pending.

•Transmission Formula Rates—In June 2021, PSE&G filed its 2020 true-up adjustment pertaining to its transmission formula rates in effect for 2020. This filing resulted in an additional annual revenue requirement of $13 million more than the 2020 originally filed revenue.

In October 2021, FERC approved a settlement agreement effective August 1, 2021 reached with the BPU Staff and the New Jersey Rate Counsel with respect to the level of PSE&G’s base transmission ROE and other formula rate matters. The settlement reduces PSE&G’s base ROE from 11.18% to 9.9% and provides that the settling parties will not seek changes to the transmission formula rate for three years. As a result of FERC’s approval of the settlement, PSE&G made the required compliance filing which was accepted by FERC in December 2021.

In 2021, PSE&G had recorded a reduction of approximately $64 million in 2021 transmission revenues as a result of the settlement.

In November 2021, PSE&G also filed its 2021 Annual Formula Rate Update with FERC for its 2022 transmission revenues under the revised ROE at 9.9% and with other settlement changes in formula rate matters, which will result in an approximate $150 million decrease in annual transmission revenue effective January 1, 2022.

•Weather Normalization Charge (WNC)—In September 2021, the BPU provisionally approved PSE&G’s 2021-2022 WNC petition to refund a $2 million overcollection from the 2020-2021 Winter Period. The overcollection will be refunded to PSE&G gas customers during the 2021-2022 Winter Period. For the 2021-2022 Winter Period, the WNC was replaced by the CIP program.

•ZEC Program—In October 2021, PSE&G filed a petition with the BPU requesting to refund a total of approximately $4 million, including interest, for overcollections resulting from the ZEC program. For the 2021 energy year, PSE&G purchased approximately $157 million in ZECs including interest, from the eligible nuclear plants selected by the BPU with the final payment made in August 2021. As a result of the collections and required ZEC payments, there were overcollected revenues, including interest of $4 million, which PSE&G now seeks to return to customers in 2022. This matter is pending.

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Note 8. Leases

As of December 31, 2021, 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 five 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.

Other

PSEG Power has operating leases for buildings, merchant transmission and equipment. These leases have remaining terms through 2025, 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 Index. Certain leases contain variable payments. Except for operating lease costs, the following tables for lessees exclude amounts in 2021 which have been classified as Held for Sale. For additional information see Note 4. Early Plant Retirements/Asset Dispositions and Impairments.

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.

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, 2021, 2020 and 2019 and any amounts capitalized as part of the cost of another asset, and the cash flows arising from lease transactions.



	PSE&G			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		%

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	PSE&G			Other			Total
	Millions
Operating Lease Costs





Year Ended December 31, 2020
Long-term Lease Costs	$	26		$	28		$	54
Short-term Lease Costs	38			7			45
Variable Lease Costs	2			29			31
Total Operating Lease Costs	$	66		$	64		$	130



Year Ended December 31, 2020
Cash Paid for Amounts Included in the Measurement of Operating Lease Liabilities	$	17		$	28		$	45

Weighted Average Remaining Lease Term in Years	12			11			11
Weighted Average Discount Rate	3.5		%	4.3		%	4.0		%



	PSE&G			Other			Total
	Millions
Operating Lease Costs





Year Ended December 31, 2019
Long-term Lease Costs	$	24		$	28		$	52
Short-term Lease Costs	14			10			24
Variable Lease Costs	2			20			22
Total Operating Lease Costs	$	40		$	58		$	98



Year Ended December 31, 2019
Cash Paid for Amounts Included in the Measurement of Operating Lease Liabilities	$	16		$	26		$	42

Weighted Average Remaining Lease Term in Years	13			11			12
Weighted Average Discount Rate	3.6		%	4.3		%	4.1		%

Operating lease liabilities as of December 31, 2021 had the following maturities on an undiscounted basis:



	PSE&G		Other		Total
	Millions
2022	$	15	$	25	$	40
2023	12		20		32
2024	10		16		26
2025	9		16		25
2026	8		15		23
Thereafter	63		60		123
Total Minimum Lease Payments	$	117	$	152	$	269

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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, 2021
	PSE&G		Other		Total
	Millions
Undiscounted Cash Flows	$	117	$	152	$	269
Reconciling Amount due to Discount Rate	(22)		(23)		(45)
Total Discounted Operating Lease Liabilities	$	95	$	129	$	224

	As of December 31, 2020
	PSE&G		Other		Total
	Millions
Undiscounted Cash Flows	$	127	$	239	$	366
Reconciling Amount due to Discount Rate	(26)		(54)		(80)
Total Discounted Operating Lease Liabilities	$	101	$	185	$	286

As of December 31, 2021, the current portions of Operating Lease Liabilities included in Other Current Liabilities were $33 million and $12 million for PSEG and PSE&G, respectively. As of December 31, 2020, the current portions of Operating Lease Liabilities included in Other Current Liabilities were $34 million and $13 million for PSEG and PSE&G, respectively.

Lessor

Other

In the third quarter of 2021, PSEG Nuclear, LLC, a wholly owned subsidiary of PSEG Power, entered into an operating lease as the lessor to lease certain parcels of land with terms of 28 years from commencement, plus five optional renewal periods of ten years.

Prior to the sale of Solar Source, 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.

Energy Holdings is the lessor in leveraged leases. See Note 9. Long-Term Investments and Note 10. Financing Receivables.

Energy Holdings is the lessor in two operating leases for domestic energy generation facilities with remaining terms through 2036, one of which has an optional renewal period and real estate assets with remaining terms through 2049. As of December 31, 2021, Energy Holdings’ property subject to these leases had a total carrying value of $124 million.

Energy Holdings was previously the lessor in operating leases for real estate assets which were sold in March 2020.

The following is the operating lease income for the years ended December 31, 2021, 2020 and 2019:



Operating Lease Income	Millions




Year Ended December 31, 2021
Fixed Lease Income	$	23
Variable Lease Income	12
Total Operating Lease Income	$	35

Year Ended December 31, 2020
Fixed Lease Income	$	15
Variable Lease Income	26
Total Operating Lease Income	$	41

Year Ended December 31, 2019
Fixed Lease Income	$	22
Variable Lease Income	23
Total Operating Lease Income	$	45

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Operating leases had the following minimum future fixed lease receipts as of December 31, 2021:



	Millions
2022	$	18
2023	18
2024	19
2025	19
2026	50
Thereafter	183
Total Minimum Future Lease Receipts	$	307

Note 9. Long-Term Investments

Long-Term Investments as of December 31, 2021 and 2020 included the following:



	As of December 31,
	2021		2020
	Millions
PSE&G
Life Insurance and Supplemental Benefits	$	89	$	100
Solar Loans	92		122
Other
Lease Investments	187		250
Equity Method Investments	173		64
Total Long-Term Investments	$	541	$	536

(A)During the three years ended December 31, 2021, 2020 and 2019, dividends from these investments were $17 million, $15 million and $15 million, respectively.

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 plus the estimated residual values at the end of the lease terms, reduced for any income not yet earned on the leases. This amount is included in Long-Term Investments on PSEG’s 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.

In September 2020, wholly owned subsidiaries of PSEG Energy Holdings L.L.C. (the Sellers) completed the sale of their ownership interests in the Powerton and Joliet generation facilities and related assets, including the assumption by the purchaser of related liabilities. The loss, net of taxes, resulting from the transaction was immaterial. In December 2020, the leveraged lease relating to our interest in the Shawville facilities was modified and extended. Accordingly, the Shawville leveraged lease was reclassified as an operating lease and the underlying assets were recorded in Property, Plant and Equipment.

In the second quarter of 2020, Energy Holdings completed its annual review of estimated residual values embedded in domestic energy leveraged leases and determined no impairments were necessary. During the second quarter of 2019, the outcome of Energy Holdings’ annual review indicated that the updated residual value estimate of the coal-fired Powerton lease was lower than the recorded residual value and the decline was deemed to be other than temporary as a result of expected future adverse market conditions. As a result, a pre-tax write-down of $58 million was reflected in Operating Revenues in 2019, calculated by comparing the gross investment in the leases before and after the revised residual estimates.

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Leveraged leases outstanding as of December 31, 2021 commenced in or prior to 2000.The following table shows Energy Holdings’ gross and net lease investment as of December 31, 2021 and 2020.



	As of December 31,
	2021		2020
	Millions
Lease Receivables (net of Non-Recourse Debt)	$	274	$	299
Estimated Residual Value of Leased Assets	—		55
Total Investment in Rental Receivables	274		354
Unearned and Deferred Income	(87)		(104)
Gross Investments in Leases	187		250
Deferred Tax Liabilities	(42)		(64)
Net Investments in Leases	$	145	$	186

The pre-tax income (loss) and income tax effects related to investments in leases, excluding gains and losses on sales and the impacts of the Tax Act, were as follows:



	Years Ended December 31,
	2021		2020		2019
	Millions
Pre-Tax Income (Loss) from Leases	$	13	$	18	$	(39)
Income Tax Expense (Benefit) on Income (Loss) from Leases	$	3	$	2	$	(22)

Equity Method Investment

PSEG had a 25% equity interest in Ørsted’s Ocean Wind project of $111 million as of December 31, 2021. For additional information see Note 5. Variable Interest Entities.

PSEG also had a 50% ownership interest in Kalaeloa, a combined-cycle generation facility in Hawaii of $62 million and $64 million as of December 31, 2021 and 2020, respectively.

Note 10. 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, 2021, none of the solar loans were impaired; however, in the event of a loan default or if a loan becomes impaired, the basis of the solar loan would be recovered through a regulatory recovery mechanism. As of December 31, 2021, none of the solar loans were delinquent. Therefore, no current credit losses have been recorded for Solar Loan Programs I, II and III. A substantial portion of these loan amounts are noncurrent and reported in Long-Term Investments on PSEG’s and PSE&G’s 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	2021		2020
	Millions
Commercial/Industrial	$	116	$	145
Residential	5		6
Total	121		151
Current Portion (included in Accounts Receivable)	(29)		(29)
Noncurrent Portion (included in Long-Term Investments)	$	92	$	122

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

Programs

Balance as of December 31, 2021

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, 2021

10 years

Total

121

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, 2021 and have an average remaining life of approximately four years.

Energy Holdings

Energy Holdings had net investments in assets subject to leveraged lease accounting of $145 million as of December 31, 2021 and $186 million as of December 31, 2020 (see Note 9. 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, 2021	As of December 31, 2021
	Millions
AA	$	8
A-	51
BBB+ to BBB	215
Total	$	274

PSEG recorded no credit losses for the leveraged leases existing on December 31, 2021. 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.

Note 11. 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, 2021 was approximately $1.2 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.

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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, 2021
	Cost		Gross Unrealized Gains		Gross Unrealized Losses		Fair Value
	Millions
Equity Securities
Domestic	$	491	$	363	$	(3)	$	851
International	346		119		(15)		450
Total Equity Securities	837		482		(18)		1,301
Available-for-Sale Debt Securities
Government	683		12		(8)		687
Corporate	637		16		(6)		647
Total Available-for-Sale Debt Securities	1,320		28		(14)		1,334
Total NDT Fund Investments (A)	$	2,157	$	510	$	(32)	$	2,635

(A) The NDT Fund Investments table excludes foreign currency of $2 million as of December 31, 2021,

which is part of the NDT Fund.



	As of December 31, 2020
	Cost		Gross Unrealized Gains		Gross Unrealized Losses		Fair Value
	Millions
Equity Securities
Domestic	$	519	$	305	$	(3)	$	821
International	388		152		(9)		531
Total Equity Securities	907		457		(12)		1,352
Available-for-Sale Debt Securities
Government	555		27		(1)		581
Corporate	528		39		(1)		566
Total Available-for-Sale Debt Securities	1,083		66		(2)		1,147
Total NDT Fund Investments (A)	$	1,990	$	523	$	(14)	$	2,499

(A) The NDT Fund Investments table excludes foreign currency of $2 million as of December 31, 2020, which is part of the NDT Fund.

Net unrealized gains on debt securities of $8 million (after-tax) were included in Accumulated Other Comprehensive Loss on PSEG’s Consolidated Balance Sheet as of December 31, 2021. The portion of net unrealized gains recognized during 2021 related to equity securities still held at the end of December 31, 2021 was $130 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,
	2021		2020
	Millions
Accounts Receivable	$	11	$	11
Accounts Payable	$	11	$	12

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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, 2021								As of December 31, 2020
	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	$	69	$	(3)	$	—	$	—	$	23	$	(2)	$	6	$	(1)
International	76		(13)		9		(2)		26		(2)		27		(7)
Total Equity Securities	145		(16)		9		(2)		49		(4)		33		(8)
Available-for-Sale Debt Securities
Government (B)	332		(5)		67		(3)		72		(1)		—		—
Corporate (C)	306		(4)		30		(2)		31		(1)		7		—
Total Available-for-Sale Debt Securities	638		(9)		97		(5)		103		(2)		7		—
NDT Trust Investments	$	783	$	(25)	$	106	$	(7)	$	152	$	(6)	$	40	$	(8)

(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 these corporate bonds because they are primarily investment grade securities.

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The proceeds from the sales of and the net gains on securities in the NDT Fund were:



	Years Ended December 31,
	2021		2020		2019
	Millions
Proceeds from Sales (A)	$	1,930	$	2,031	$	1,614
Net Realized Gains (Losses):
Gross Realized Gains	$	236	$	214	$	107
Gross Realized Losses	(70)		(94)		(53)
Net Realized Gains (Losses) on NDT Fund (B)	166		120		54
Net Unrealized Gains (Losses) on Equity Securities	19		120		196
Impairment of Available-for-Sale Debt Securities (C)	—		(3)		—
Net Gains (Losses) on NDT Fund Investments	$	185	$	237	$	250

(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.

(C)PSEG Power recognized an impairment of available-for-sale debt securities in 2020. PSEG Power’s policy is to sell all securities that are rated below investment grade.

The NDT Fund debt securities held as of December 31, 2021 had the following maturities:



Time Frame	Fair Value
	Millions
Less than one year	$	24
1 - 5 years	335
6 - 10 years	234
11 - 15 years	84
16 - 20 years	113
Over 20 years	544
Total NDT Available-for-Sale Debt Securities	$	1,334

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, 2021
	Cost		Gross Unrealized Gains		Gross Unrealized Losses		Fair Value
	Millions
Domestic Equity Securities	$	14	$	12	$	—	$	26
Available-for-Sale Debt Securities
Government	107		1		(1)		107
Corporate	105		5		(1)		109
Total Available-for-Sale Debt Securities	212		6		(2)		216
Total Rabbi Trust Investments	$	226	$	18	$	(2)	$	242



	As of December 31, 2020
	Cost		Gross Unrealized Gains		Gross Unrealized Losses		Fair Value
	Millions
Domestic Equity Securities	$	21	$	10	$	—	$	31
Available-for-Sale Debt Securities
Government	94		6		—		100
Corporate	123		12		—		135
Total Available-for-Sale Debt Securities	217		18		—		235
Total Rabbi Trust Investments	$	238	$	28	$	—	$	266

Net unrealized gains (losses) on debt securities of $3 million (after-tax) were included in Accumulated Other Comprehensive Loss on PSEG’s Consolidated Balance Sheet as of December 31, 2021. The portion of net unrealized gains recognized during 2021 related to equity securities still held at the end of December 31, 2021 was $1 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,
	2021		2020
	Millions
Accounts Receivable	$	1	$	1
Accounts Payable	$	—	$	1

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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, 2021								As of December 31, 2020
	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)	$	57	$	—	$	16	$	(1)	$	19	$	—	$	—	$	—
Corporate (B)	40		(1)		5		—		2		—		1		—
Total Available-for-Sale Debt Securities	97		(1)		21		(1)		21		—		1		—
Rabbi Trust Investments	$	97	$	(1)	$	21	$	(1)	$	21	$	—	$	1	$	—

(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 these corporate bonds because they are primarily investment grade.

The proceeds from the sales of and the net gains on securities in the Rabbi Trust Fund were:



	Years Ended December 31,
	2021		2020		2019
	Millions
Proceeds from Rabbi Trust Sales	$	170	$	203	$	173
Net Realized Gains (Losses):
Gross Realized Gains	$	16	$	19	$	7
Gross Realized Losses	(8)		(6)		(3)
Net Realized Gains (Losses) on Rabbi Trust (A)	8		13		4
Net Unrealized Gains (Losses) on Equity Securities	1		3		6
Net Gains (Losses) on Rabbi Trust Investments	$	9	$	16	$	10

(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, 2021 had the following maturities:



Time Frame	Fair Value
	Millions
Less than one year	$	—
1 - 5 years	40
6 - 10 years	24
11 - 15 years	10
16 - 20 years	25
Over 20 years	117
Total Rabbi Trust Available-for-Sale Debt Securities	$	216

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,
	2021		2020
	Millions
PSE&G	$	43	$	51
Other	199		215
Total Rabbi Trust Investments	$	242	$	266

Note 12. Intangibles

As of December 31, 2021 and 2020, PSEG had intangible assets of $20 million and $158 million, respectively, related to emissions allowances and RECs. Emissions allowances and RECs are recorded at cost and evaluated for impairment at least annually. Emissions expense includes impairments of emissions allowances, if any, and costs for emissions, which is recorded as emissions occur. As load is served under contracts requiring energy from renewable sources, the related expense is recorded.

The changes to PSEG’s intangible assets during 2020 and 2021 are as follows:



	Emissions Allowances		RECs		Total Intangibles
	Millions
Balance as of January 1, 2020	$	104	$	45	$	149
Retirements	(9)		(93)		(102)
Purchases	17		94		111
Balance as of December 31, 2020	$	112	$	46	$	158
Retirements	(58)		(114)		(172)
Purchases	9		89		98
Sales and Transfers (A)	(62)		(1)		(63)
Impairments	(1)		—		(1)
Balance as of December 31, 2021	$	—	$	20	$	20

(A)Includes $52 million classified as Assets Held for Sale. See Note 4. Early Plant Retirements/Asset Dispositions and Impairments.

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Note 13. 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 11. Trust Investments. PSEG also identified conditional AROs primarily related to PSEG’s fossil generation units, including liabilities for removal of asbestos, stored hazardous liquid material and underground storage tanks from industrial power sites, and demolition of certain plants, and the restoration of the sites at which they reside, when the plants are no longer in service. 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 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 2020 and 2021 are presented in the following table:



	PSEG		PSE&G		Other
	Millions
ARO Liability as of January 1, 2020	$	1,087	$	303	$	784
Liabilities Settled	(9)		(7)		(2)

Accretion Expense	42		—		42
Accretion Expense Deferred and Recovered in Rate Base (A)	17		17		—
Revision to Present Values of Estimated Cash Flows	75		1		74
ARO Liability as of December 31, 2020	$	1,212	$	314	$	898
Liabilities Settled	(15)		(14)		(1)
Adjustments (B)	(37)		—		(37)
Accretion Expense	44		—		44
Accretion Expense Deferred and Recovered in Rate Base (A)	16		16		—
Revision to Present Values of Estimated Cash Flows	353		47		306
ARO Liability as of December 31, 2021	$	1,573	$	363	$	1,210

(A)Not reflected as expense in Consolidated Statements of Operations.

(B)Represents amounts related to the sale of the solar plants and the fossil generating assets classified as Held for Sale.

During 2021, PSE&G recorded an increase to its ARO liabilities primarily due to the impact of increases in labor rates and other costs, partially offset by decreases from changes in inflation and discount rate assumptions. Those changes had no impact on PSE&G’s Consolidated Statement of Operations.

In April 2021, the BPU awarded ZECs to PSEG Power’s Salem 1, Salem 2 and Hope Creek nuclear plants for an additional three years through May 2025. Concurrent with the BPU’s decision, PSEG reassessed the Asset Retirement Cost (ARC) and

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ARO assumptions related to the Salem and Hope Creek units. This resulted in an increase to the ARC asset and ARO liability of $51 million, primarily due to lower discount rates and higher inflation. See Note 4. Early Plant Retirements/Asset Dispositions and Impairments for additional information on ZECs.

In December 2021, PSEG recorded an additional increase to its ARO liabilities primarily due to changes in decommissioning assumptions related to its nuclear units of $255 million. The changes in the decommissioning assumptions relate to the inclusion of certain spent fuel costs and previously assumed levels of reimbursement by the federal government as prescribed under the Nuclear Waste Policy Act. These changes had an immaterial impact on PSEG’s Consolidated Statement of Operations. In addition, PSEG reviewed its probabilities of early retirement on its nuclear units and concluded that no adjustments were necessary as of December 31, 2021.

In early 2020, the NRC approved Peach Bottom’s second license extension for both units. Concurrent with the license extensions, PSEG extended the useful life of the asset to match the 80-year life expectation and reassessed the related ARC and ARO assumptions. This resulted in an increase to the ARC asset and ARO liability of $74 million, primarily due to lower discount rates offset by a longer discounting period as a result of the Peach Bottom units’ longer expected useful life.

Note 14. 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 and Pension Plan II. 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 its 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.

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, 2021 and 2020. 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
	2021		2020		2021		2020
	Millions
Change in Benefit Obligation
Benefit Obligation at Beginning of Year (A)	$	7,507	$	6,892	$	1,306	$	1,285
Service Cost	151		141		9		9
Interest Cost	140		192		22		34
Actuarial (Gain) Loss (B)	(199)		615		(90)		32
Gross Benefits Paid	(359)		(333)		(50)		(50)
Plan Amendments	—		—		—		(4)

Benefit Obligation at End of Year (A)	$	7,240	$	7,507	$	1,197	$	1,306
Change in Plan Assets
Fair Value of Assets at Beginning of Year	$	6,368	$	5,929	$	564	$	540
Actual Return on Plan Assets	886		761		79		70
Employer Contributions	11		11		13		4
Gross Benefits Paid	(359)		(333)		(50)		(50)

Fair Value of Assets at End of Year	$	6,906	$	6,368	$	606	$	564
Funded Status
Funded Status (Plan Assets less Benefit Obligation)	$	(334)	$	(1,139)	$	(591)	$	(742)
Additional Amounts Recognized in the Consolidated Balance Sheets
Current Accrued Benefit Cost (C)	$	(16)	$	(11)	$	(19)	$	(12)
Noncurrent Accrued Benefit Cost	(318)		(1,128)		(572)		(730)
Amounts Recognized	$	(334)	$	(1,139)	$	(591)	$	(742)
Additional Amounts Recognized in Accumulated Other Comprehensive Income (Loss), Regulated Assets and Deferred Assets (D)
Prior Service Credit	$	—	$	—	$	(181)	$	(310)
Net Actuarial Loss	1,643		2,354		193		364
Total	$	1,643	$	2,354	$	12	$	54

(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 gain in 2021 was due primarily to an increase in the discount rate. For OPEB, the net actuarial gain in 2021 was due primarily to an increase in the discount rate coupled with lower than expected claims experience. For pension benefits, the net actuarial loss in 2020 was due primarily to a decrease in the discount rate. For OPEB, the net actuarial loss in 2020 was due primarily to a decrease in the discount rate, partially offset by actuarial gains driven by lower than expected claims experience.

(C)Includes ($5) million and ($7) million for pension benefits and other benefits, respectively, as of December 31, 2021 classified as Held for Sale. For additional information, see Note 4. Early Plant Retirements/Asset Dispositions and Impairments.

(D)Includes $495 million ($355 million, after-tax) and $760 million ($545 million, after-tax) in Accumulated Other Comprehensive Loss related to Pension and OPEB as of December 31, 2021 and 2020, respectively. Also includes Regulatory Assets of $1,043 million and Deferred Assets of $117 million as of December 31, 2021 and Regulatory Assets of $1,489 million and Deferred Assets of $159 million as of December 31, 2020.

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, 2021, PSEG had funded approximately 95% of its projected pension benefit obligation. This percentage does not include $242 million of assets in the Rabbi Trust as of December 31, 2021, 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 $174 million.

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Accumulated Benefit Obligation

The accumulated benefit obligation for all PSEG’s defined benefit pension plans was $7.1 billion as of December 31, 2021 and $7.3 billion as of December 31, 2020.

The following table provides the components of net periodic benefit cost relating to all qualified and nonqualified pension and OPEB plans on an aggregate basis for PSEG, excluding Servco for the years ended December 31, 2021, 2020 and 2019. Amounts shown do not reflect the impacts of capitalization and co-owner allocations. Only the service cost component is eligible for capitalization, when applicable.



	Pension Benefits Years Ended December 31,						Other Benefits Years Ended December 31,
	2021		2020		2019		2021		2020		2019
	Millions
Components of Net Periodic Benefit (Credits) Costs
Service Cost (included in O&M Expense)	$	151	$	141	$	123	$	9	$	9	$	10
Non-Service Components of Pension and OPEB (Credits) Costs
Interest Cost	140		192		218		22		34		45
Expected Return on Plan Assets	(476)		(443)		(408)		(42)		(39)		(36)
Amortization of Net
Prior Service Credit	—		(10)		(18)		(129)		(128)		(128)
Actuarial Loss	103		92		96		44		47		50
Non-Service Components of Pension and OPEB (Credits) Costs	(233)		(169)		(112)		(105)		(86)		(69)
Total Benefit (Credits) Costs	$	(82)	$	(28)	$	11	$	(96)	$	(77)	$	(59)

Pension costs and OPEB costs for PSEG and PSE&G are detailed as follows:



	Pension Benefits Years Ended December 31,						Other Benefits Years Ended December 31,
	2021		2020		2019		2021		2020		2019
	Millions
PSE&G	$	(64)	$	(27)	$	—	$	(92)	$	(76)	$	(62)
Other	(18)		(1)		11		(4)		(1)		3
Total Benefit (Credits) Costs	$	(82)	$	(28)	$	11	$	(96)	$	(77)	$	(59)

The following table provides the pre-tax changes recognized in Accumulated Other Comprehensive Income (Loss), Regulatory Assets and Deferred Assets:



	Pension				OPEB
	2021		2020		2021		2020
	Millions
Net Actuarial (Gain) Loss in Current Period	$	(608)	$	296	$	(127)	$	2
Amortization of Net Actuarial Gain (Loss)	(103)		(92)		(44)		(47)
Prior Service Cost (Credit) in Current Period	—		—		—		(5)
Amortization of Prior Service Credit	—		10		129		128
Total	$	(711)	$	214	$	(42)	$	78

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The following assumptions were used to determine the benefit obligations and net periodic benefit costs:



	Pension Benefits						Other Benefits
	2021		2020		2019		2021		2020		2019
Weighted-Average Assumptions Used to Determine Benefit Obligations as of December 31
Discount Rate	2.94	%	2.61	%	3.30	%	2.82	%	2.46	%	3.20	%
Rate of Compensation Increase	4.40	%	4.40	%	3.90	%	4.40	%	4.40	%	3.90	%
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	2.61	%	3.30	%	4.41	%	2.46	%	3.20	%	4.31	%
Service Cost Interest Rate	2.94	%	3.49	%	4.58	%	2.76	%	3.50	%	4.48	%
Interest Cost Interest Rate	1.91	%	2.87	%	4.03	%	1.70	%	2.87	%	3.91	%
Expected Return on Plan Assets	7.70	%	7.70	%	7.80	%	7.69	%	7.70	%	7.79	%
Rate of Compensation Increase	4.40	%	3.90	%	3.90	%	4.40	%	3.90	%	3.90	%
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							6.14	%	6.37	%	6.68	%
Ultimate Rate							4.75	%	4.75	%	4.75	%
Year Ultimate Rate Reached							2029		2029		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 19. 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, 2021, the pension plan interest and OPEB plan interest in such assets of the Master Trust were approximately 92% and 8%, respectively.

The following tables present information about the investments measured at fair value on a recurring basis as of December 31, 2021 and 2020, 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, 2021
			Quoted Market Prices for Identical Assets		Significant Other Observable Inputs		Significant Unobservable Inputs
Description	Total		(Level 1)		(Level 2)		(Level 3)
	Millions
Cash Equivalents (A)	$	45	$	45	$	—	$	—
Equity Securities
Common Stock (B)	1,959		1,959		—		—
Commingled (C)	1,948		1,085		863		—
Preferred Stock (B)	2		2		—		—
Other (D)	2		2		—		—
Debt Securities (E)
U.S. Treasury	1,761		—		1,761		—


Commingled	4		4		—		—
Subtotal Fair Value	$	5,721	$	3,097	$	2,624	$	—
Measured at net asset value practical expedient
Commingled—Equities (F)	1,403
Real Estate Investment (G)	372
Private Equity (H)	3
Total Fair Value (I)	$	7,499



	Recurring Fair Value Measurements as of December 31, 2020
			Quoted Market Prices for Identical Assets		Significant Other Observable Inputs		Significant Unobservable Inputs
Description	Total		(Level 1)		(Level 2)		(Level 3)
	Millions
Cash Equivalents (A)	$	85	$	85	$	—	$	—
Equity Securities
Common Stock (B)	1,763		1,763		—		—
Commingled (C)	1,964		1,025		939		—
Preferred Stock (B)	10		10		—		—
Other (D)	1		1		—		—
Debt Securities (E)
U.S. Treasury	419		—		419		—
Government—Other	258		—		258		—
Corporate	823		—		823		—
Commingled	4		4		—		—
Subtotal Fair Value	$	5,327	$	2,888	$	2,439	$	—
Measured at net asset value practical expedient
Commingled—Equities (F)	1,283
Real Estate Investment (G)	306
Private Equity (H)	5
Total Fair Value (I)	$	6,921

(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 and preferred stocks are measured using observable data in active markets and considered Level 1.

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(C)Commingled Funds that allow daily redemption at their daily published NAV without restrictions are classified as Level 1. 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)Investment in a publicly traded limited partnership.

(E)Debt securities include mainly investment grade corporate and municipal bonds, U.S. Treasury obligations and Federal Agency asset-backed securities with a wide range of maturities. 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.

(F)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 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.

(G)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.

(H)Private equity investments primarily include various limited partnerships that invest in either operating companies through acquisitions or developing a portfolio of non-U.S. distressed investments to maximize total return on capital. These investments are valued at NAV (or its equivalent) on a quarterly basis and have significant redemption restrictions preventing redemption until fund liquidation and limited ability to sell these investments. Fund liquidation is not expected to occur for several more years. These investments are not included in the fair value hierarchy in accordance with the guidance on NAV practical expedient.

(I)Excludes net receivables of $11 million and $10 million as of December 31, 2021 and 2020, 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 and $1 million as of December 31, 2021 and 2020, respectively.

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	2021		2020
Equity Securities	71	%	72	%
Debt Securities	23		22
Other Investments	6		6
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 (14% as of December 31, 2021) 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 7.7% for 2021 and will be 7.2% for 2022. This expected return includes a premium for active management.

Plan Contributions

PSEG does not plan to contribute to its pension and OPEB plans in 2022. 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

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subsequent calendar year. As a result, the market volatility in 2021 associated with the ongoing coronavirus pandemic is not expected to impact PSEG’s pension contributions in 2022.

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
2022	$	402	$	82
2023	386		82
2024	397		82
2025	405		81
2026	414		80
2027-2031	2,154		368
Total	$	4,158	$	775

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,
	2021		2020		2019
	Millions
PSE&G	$	28	$	27	$	25
Other	16		16		15
Total Employer Matching Contributions	$	44	$	43	$	40

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 5. Variable Interest Entities. 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, 2021 and 2020. 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
	2021		2020		2021		2020
	Millions
Change in Benefit Obligation
Benefit Obligation at Beginning of Year (A)	$	569	$	453	$	699	$	626
Service Cost	38		33		23		20
Interest Cost	14		14		18		20
Actuarial (Gain) Loss (B)	(18)		74		(89)		42
Gross Benefits Paid	(7)		(5)		(11)		(9)
Plan Amendments	—		—		—		—
Benefit Obligation at End of Year (A)	$	596	$	569	$	640	$	699
Change in Plan Assets
Fair Value of Assets at Beginning of Year	$	343	$	282	$	—	$	—
Actual Return on Plan Assets	49		36		—		—
Employer Contributions	37		30		11		9
Gross Benefits Paid	(7)		(5)		(11)		(9)
Fair Value of Assets at End of Year	$	422	$	343	$	—	$	—
Funded Status
Funded Status (Plan Assets less Benefit Obligation)	$	(174)	$	(226)	$	(640)	$	(699)
Additional Amounts Recognized in the Consolidated Balance Sheets
Accrued Pension Costs of Servco	$	(174)	$	(226)	N/A		N/A
OPEB Costs of Servco	N/A		N/A		(640)		(699)
Amounts Recognized (C)	$	(174)	$	(226)	$	(640)	$	(699)

(B)For pension benefits, the net actuarial gain in 2021 was due primarily to an increase in the discount rate. For OPEB, the net actuarial gain in 2021 was due primarily to updated assumptions. For pension benefits, the net actuarial loss in 2020 was due primarily to a decrease in the discount rate. For OPEB, the net actuarial loss in 2020 was due primarily to a decrease in the discount rate, partially offset by actuarial gains driven by lower than expected participation experience.

(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 2021, 2020 and 2019 were $37 million, $30 million and $28 million, respectively. Servco has contributed its entire planned contribution amount to its pension plan trusts during 2021. The OPEB-related revenues earned and costs incurred were $11 million, $9 million and $6 million in 2021, 2020 and 2019, respectively. The following assumptions were used to determine the benefit obligations of Servco:



	Pension Benefits						Other Benefits
	2021		2020		2019		2021		2020		2019
Weighted-Average Assumptions Used to Determine Benefit Obligations as of December 31
Discount Rate	3.21	%	2.98	%	3.52	%	3.28	%	3.08	%	3.60	%
Rate of Compensation Increase	3.95	%	3.95	%	3.25	%	3.95	%	3.95	%	3.25	%
Cash Balance Interest Crediting Rate	3.75	%	3.75	%	3.75	%	N/A		N/A		N/A
Assumed Health Care Cost Trend Rates as of December 31
Health Care Costs
Immediate Rate							6.48	%	6.70	%	6.94	%
Ultimate Rate							4.75	%	4.75	%	4.75	%
Year Ultimate Rate Reached							2029		2029		2029

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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 19. 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, 2021 and 2020, including the fair value measurements and the levels of inputs used in determining those fair values.



	Recurring Fair Value Measurements as of December 31, 2021
			Quoted Market Prices for Identical Assets		Significant Other Observable Inputs		Significant Unobservable Inputs
Description	Total		(Level 1)		(Level 2)		(Level 3)
	Millions
Cash Equivalents	$	1	$	1	$	—	$	—
Equity Securities
Common Stock (A)	34		34		—		—
Commingled (B)	285		—		285		—
Commingled Bonds (B)	102		—		102		—
Total	$	422	$	35	$	387	$	—



	Recurring Fair Value Measurements as of December 31, 2020
			Quoted Market Prices for Identical Assets		Significant Other Observable Inputs		Significant Unobservable Inputs
Description	Total		(Level 1)		(Level 2)		(Level 3)
	Millions
Cash Equivalents	$	1	$	1	$	—	$	—
Commingled Equities (B)	259		—		259		—
Commingled Bonds (B)	83		—		83		—
Total	$	343	$	1	$	342	$	—

(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	2021		2020
Equity Securities	76	%	76	%
Debt Securities	24		24
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 (16% at December 2021) 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

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allocation. The expected long-term rate of return on plan assets was 7.6% for 2021 and will be the same for 2022. This expected return includes a premium for active management.

Plan Contributions

Servco plans to contribute $30 million into its pension plan during 2022. 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. As a result, the market volatility in 2021 associated with the ongoing coronavirus pandemic is not expected to impact Servco’s pension contributions in 2022.

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
2022	$	10	$	9
2023	12		11
2024	14		13
2025	17		14
2026	19		16
2027-2031	136		104
Total	$	208	$	167

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 amounts expensed by Servco for employer matching contributions for the years ended December 31, 2021, 2020 and 2019 were $9 million, $9 million and $8 million, respectively, and pursuant to the OSA, Servco recognizes Operating Revenues for the reimbursement of these costs.

Note 15. 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,

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•its subsidiaries would have to fully utilize the credit granted to them by every counterparty to whom PSEG Power has provided a guarantee, and

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

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

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

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

The following table shows the face value of PSEG Power’s outstanding guarantees, current exposure and margin positions as of December 31, 2021 and 2020.



	As of December 31, 2021		As of December 31, 2020
	Millions
Face Value of Outstanding Guarantees	$	1,959	$	1,792
Exposure under Current Guarantees	$	176	$	128

Letters of Credit Margin Posted	$	80	$	128
Letters of Credit Margin Received	$	242	$	45

Cash Deposited and Received
Counterparty Cash Collateral Deposited	$	60	$	—
Counterparty Cash Collateral Received	$	(1)	$	(5)
Net Broker Balance Deposited (Received)	$	785	$	59

Additional Amounts Posted
Other Letters of Credit	$	67	$	42

As part of determining credit exposure, PSEG Power nets receivables and payables with the corresponding net fair values of energy contracts. See Note 18. 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.

Certain Potentially Responsible Parties (PRPs), including PSE&G and PSEG Power, formed a Cooperating Parties Group (CPG) and agreed to conduct a Remedial Investigation and Feasibility Study of the LPRSA. The CPG allocated, on an interim

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basis, the associated costs among its members. The interim allocation is subject to change. In June 2019, the EPA conditionally approved the CPG’s Remedial Investigation. In September 2021, the EPA approved the CPG’s Feasibility Study (FS), which evaluated various adaptive management scenarios for the remediation of only the upper 9 miles of the LPRSA. In October 2021, the EPA announced a Record of Decision (ROD) outlining its selection of an adaptive management scenario for the upper 9 miles from the options presented in the FS (the Upper 9 ROD Remedy). Specifically, the Upper 9 ROD Remedy calls for dredging and capping contaminated sediments from certain areas of the upper 9 miles at an estimated cost of $550 million, and then assessing the results. Based on the results, the EPA may determine that additional remediation work will be required in the future. The cost estimates in the Upper 9 ROD Remedy are substantively identical to those in the proposed remediation plan that the EPA issued in April 2021. PSEG has previously adjusted its accrued liability based on the cost estimates in the proposed remediation plan, so no additional accrual adjustment is warranted for the Upper 9 ROD Remedy.

Separately, the EPA has released a ROD for the LPRSA’s lower 8.3 miles that requires the removal of sediments at an estimated cost of $2.3 billion (the Lower 8.3 ROD Remedy). An EPA-commenced process to allocate the associated costs is underway and PSEG cannot predict the outcome. The allocation does not address certain costs incurred by the EPA for which they may be entitled to reimbursement and which may be material. Occidental Chemical Corporation, one of the PRPs, has commenced the design of the Lower 8.3 ROD Remedy, but declined to participate in the allocation process. Instead, it filed suit against PSE&G and others seeking cost recovery and contribution under CERCLA but has not quantified alleged damages. The litigation is ongoing and PSEG cannot predict the outcome.

Two PRPs, Tierra Solutions, Inc. (Tierra) and Maxus Energy Corporation (Maxus), have filed for Chapter 11 bankruptcy. The trust representing the creditors in this proceeding has filed a complaint asserting claims against Tierra’s and Maxus’ current and former parent entities, among others. Any damages awarded may be used to fund the remediation of the LPRSA.

As of December 31, 2021, 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 Other Noncurrent 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.

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.

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 11 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.

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, 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 $220 million and $249 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 $220 million as of December 31, 2021. Of this amount, $33 million was recorded in Other Current Liabilities and $187 million was reflected as Environmental Costs in Noncurrent Liabilities. PSE&G has recorded a $220 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

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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.

CWA Section 316(b) Rule

The EPA’s CWA Section 316(b) rule establishes requirements for the regulation of cooling water intakes at existing power plants and industrial facilities with a design flow of more than two million gallons of water per day. The EPA requires that National Pollutant Discharge Elimination System permits be renewed every five years and that each state Permitting Director manage renewal permits for its respective power generation facilities on a case by case basis. The NJDEP manages the permits under the New Jersey Pollutant Discharge Elimination System (NJPDES) program. Connecticut and New York also have permits to manage their respective pollutant discharge elimination system programs.

In June 2016, the NJDEP issued a final NJPDES 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 but no hearing date has been established.

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.

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

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 have been responsible for fulfilling all the requirements of a PJM load-serving entity including the provision of capacity, energy, ancillary services, transmission and any other services required by PJM. BGS suppliers assume all volume risk and customer migration risk and must satisfy New Jersey’s renewable portfolio standards. Beginning with the 2021 BGS auction, transmission became the responsibility of the New Jersey EDCs, and is no longer a component of the BGS auction product for either the RSCP or CIEP auctions. BGS suppliers serving load from the 2018, 2019 and 2020 BGS auctions had the option to transfer the transmission obligation to the New Jersey EDCs as of February 2021. Suppliers that did so had their total BGS payment from the EDCs reduced to reflect the transfer of the transmission obligation to the EDCs.

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, 2022 is $276.26 per MW-day, replacing the BGS-CIEP auction year price ending May 31, 2022 of $351.06 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
	2019	2020	2021	2022
36-Month Terms Ending	May 2022	May 2023	May 2024	May 2025	(A)
Load (MW)	2,800	2,800	2,900	2,800
$ per MWh	$98.04	$102.16	$64.80	$76.30

(A)Prices set in the 2022 BGS auction will become effective on June 1, 2022 when the 2019 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 26. 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 nuclear fuel commitments cover approximately 100% of its estimated uranium, enrichment and fabrication requirements through 2022 and a significant portion through 2023 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, 2021, the total minimum purchase requirements included in these commitments were as follows:



Fuel Type	PSEG Power’s Share of Commitments through 2026
	Millions
Nuclear Fuel
Uranium	$	226
Enrichment	$	331
Fabrication	$	193
Natural Gas (A)	$	1,266

(A)Approximately $39 million of commitments related to natural gas were transferred with the sale of PSEG Power’s fossil generation plants in February 2022.

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. We are 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.

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Pending Tropical Storm Matter

Following the effects of Tropical Storm Isaias, the New York Attorney General (AG) initiated an inquiry into PSEG LI’s preparation and response to the storm. In addition, the Department of Public Service (DPS) within the New York State Public Service Commission launched an investigation of the State’s electric service providers’, including PSEG LI’s, preparation and response to the storm. The DPS issued an interim storm investigation report finding that PSEG LI violated its Emergency Response Plan and DPS Regulations, and recommended that LIPA consider taking various actions, including terminating or renegotiating the OSA. LIPA also issued a report with recommendations for improvements to PSEG LI’s structure and processes, and recommended that LIPA either renegotiate or terminate the OSA.

PSEG LI agreed with LIPA that it would fund approximately $7 million in claims by customers for food and medication spoilage costs incurred as a result of being without electric service during the storm.

In December 2020, LIPA filed a complaint against PSEG LI in New York State court alleging multiple breaches of the OSA in connection with PSEG LI’s preparation for and response to Tropical Storm Isaias seeking specific performance and $70 million in damages. In June 2021, LIPA and PSEG LI executed a non-binding term sheet, which is expected to guide amendments to the OSA. The term sheet includes several changes to the OSA, including shifting a portion of PSEG LI’s fixed revenues to incentive compensation and subjecting a portion of revenue to the potential imposition of penalties by the DPS due to certain performance failures by PSEG LI, and resolves all of LIPA’s claims related to Tropical Storm Isaias and the DPS investigation. An amended OSA based on the term sheet was agreed to by both parties and approved by the LIPA Board in December 2021. In January 2022, the New York AG approved the Amended OSA and it has been submitted to the New York Comptroller for approval, which approval must occur by April 1, 2022 (such date is subject to amendment by mutual agreement of PSEG LI and LIPA) in order for the Amended OSA to become binding and effective. Such approval would result in retroactive effectiveness to January 1, 2022 for purposes of compensation. The OSA contract term will continue through 2025, with a mutual option to extend for five years. No assurances can be given regarding obtaining the New York Comptroller approval and the closing of the inquiry by the AG.

In the event that the Amended OSA is not approved by the New York Comptroller on April 1, 2022, PSEG LI intends to vigorously defend itself with regard to the allegations in LIPA’s complaint alleging breaches of the OSA. A decision in this proceeding requiring specific performance or the payment of damages by PSEG LI or resulting in the termination of the OSA could have a material adverse effect on PSEG’s results of operations and financial condition.

BPU Audit of PSE&G

In September 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 periodically as required by New Jersey statutes/regulations. Phase 1 of the planned audit will review 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 will be a comprehensive management audit, which will address, among other things, executive management, corporate governance, system operations, human resources, cyber security, compliance with customer protection requirements and customer safety. The audit officially began in late May 2021 and is in the data collection phase. 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, 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

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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, PSE&G’s or PSEG Power’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.

Ongoing Coronavirus Pandemic

PSE&G, PSEG Power and PSEG LI are providing essential services during this national emergency related to the ongoing coronavirus (COVID-19) pandemic. The COVID-19 pandemic and associated government actions and economic effects continue to impact our businesses. PSEG and its subsidiaries have incurred additional expenses to protect our employees and customers, and PSE&G is experiencing significantly higher bad debts and lower cash collections from customers due to the moratorium on shutoffs for residential customers that has been extended through December 31, 2021. PSE&G has deferred the impact of these costs for future recovery. The potential future impact of the pandemic and the associated economic impacts, which could extend beyond the duration of the pandemic, could have risks that drive certain accounting considerations. The ultimate impact of the ongoing coronavirus pandemic is highly uncertain and cannot be predicted at this time.

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, 2021, nuclear sites were required to purchase $450 million of primary liability coverage for each site (through ANI). 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 $13.1 billion. PSEG Power’s maximum aggregate assessment per incident is $433 million (based on PSEG Power’s ownership interests in Salem, Hope Creek and Peach Bottom) and its maximum aggregate annual assessment per incident is $65 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 $46 million. NEIL requires its members to maintain an 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 $3.2 billion plus such additional amounts as NEIL recovers for such losses from reinsurance, indemnity and any other source applicable to such losses.

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Note 16. Debt and Credit Facilities

Long-Term Debt



			As of December 31,
		Maturity	2021		2020
			Millions
PSEG



Senior Notes:
2.00%		2021	$	—	$	300
2.65%		2022	700		700
0.84%		2023	750		—
2.88%		2024	750		750
0.80%		2025	550		550
1.60%		2030	550		550
2.45%		2031	750		—
8.63%	(A)	2031	96		96
Total Senior Notes			4,146		2,946
Principal Amount Outstanding			4,146		2,946
Amounts Due Within One Year			(700)		(300)
Net Unamortized Discount and Debt Issuance Costs			(22)		(17)
Total Long-Term Debt of PSEG			$	3,424	$	2,629

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		As of December 31,
	Maturity	2021		2020
		Millions
PSE&G
First and Refunding Mortgage Bonds (B):
9.25%	2021	$	—	$	134
8.00%	2037	7		7
5.00%	2037	8		8
Total First and Refunding Mortgage Bonds		15		149
Medium-Term Notes (B):
1.90%	2021	—		300
2.38%	2023	500		500
3.25%	2023	325		325
3.75%	2024	250		250
3.15%	2024	250		250
3.05%	2024	250		250
3.00%	2025	350		350
2.25%	2026	425		425
0.95%	2026	450		—
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		—
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		—
Total MTNs		11,875		10,850
Principal Amount Outstanding		11,890		10,999
Amounts Due Within One Year		—		(434)
Net Unamortized Discount and Selling Expense		(95)		(90)
Total Long-Term Debt of PSE&G		$	11,795	$	10,475

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			As of December 31,
		Maturity	2021		2020
			Millions
PSEG Power
Senior Notes:
3.00%		2021	$	—	$	700
4.15%		2021	—		250
3.85%		2023	—		700
4.30%		2023	—		250
8.63%	(A)	2031	—		404
Total Senior Notes (C)			—		2,304
Pollution Control Notes:
Floating Rate (C)		2022	—		44
Total Pollution Control Notes			—		44
Principal Amount Outstanding			—		2,348
Amounts Due Within One Year			—		(950)
Net Unamortized Discount and Debt Issuance Costs			—		(6)
Total Long-Term Debt of PSEG Power			$	—	$	1,392

(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.

(C)All outstanding Senior Notes and the Pennsylvania Economic Development Financing Authority Variable Rate Bonds (PEDFA) of PSEG Power were redeemed during 2021 as described below.

Long-Term Debt Maturities

The aggregate principal amounts of maturities for each of the five years following December 31, 2021 are as follows:



Year	PSEG		PSE&G		Total

2022	$	700	$	—	$	700
2023	750		825		1,575
2024	750		750		1,500
2025	550		350		900
2026	—		875		875
Thereafter	1,396		9,090		10,486
Total	$	4,146	$	11,890	$	16,036

Long-Term Debt Financing Transactions

During 2021, PSEG and its subsidiaries had the following Long-Term Debt issuances, maturities and redemptions:

PSEG

•issued $750 million of 0.84% Senior Notes due November 2023,

•issued $750 million of 2.45% Senior Notes due November 2031, and

•retired $300 million of 2.00% Senior Notes at maturity.

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PSE&G

•issued $450 million of 0.95% Secured Medium-Term Notes, Series N, due March 2026,

•issued $450 million of 3.00% Secured Medium-Term Notes, Series N, due March 2051,

•issued $425 million of 1.90% Secured Medium-Term Notes, Series N, due August 2031,

•retired $300 million of 1.90% Secured Medium-Term Notes, Series K, at maturity, and

•retired $134 million of 9.25% Mortgage Bonds, Series CC, at maturity.

PSEG Power

•redeemed in May at par $700 million of 3.00% Senior Notes due to mature in June 2021,

•redeemed in June at par $250 million of 4.15% Senior Notes due to mature in September 2021, and

•redeemed in August $44 million of PEDFA Variable Rate Bonds.

In October 2021, PSEG redeemed all remaining outstanding Senior Notes of PSEG Power due to covenants that could trigger a default from the sale of PSEG Power’s fossil generating assets. This included $700 million of 3.85% Senior Notes due to mature in June 2023, $250 million of 4.30% Senior Notes due to mature in November 2023, and $404 million of 8.63% Senior Notes due to mature in April 2031. These Senior Notes were redeemed at a redemption price that included a "make-whole" premium of approximately $294 million plus any interest accrued and unpaid to the redemption date, in each case, calculated in accordance with the indenture governing the Senior Notes. The debt redemption and “make whole” premium were funded with a short-term loan from PSEG and borrowings under PSEG Power’s credit facility. In addition, approximately $4 million of other non-cash debt extinguishment costs were recorded in October 2021.

Short-Term Liquidity

The commitments under the $4.1 billion credit facilities are provided by a diverse bank group. As of December 31, 2021, the total available credit capacity was $2.9 billion.

As of December 31, 2021, no single institution represented more than 8% of the total commitments in the credit facilities.

As of December 31, 2021, the total credit capacity was in excess of the anticipated maximum liquidity requirements over PSEG’s 12-month planning horizon, including access to external financing to meet redemptions.

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.

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The total credit facilities and available liquidity as of December 31, 2021 were as follows:



	As of December 31, 2021
Company/Facility	Total Facility		Usage (E)		Available Liquidity		Expiration Date	Primary Purpose
	Millions
PSEG
5-year Credit Facilities (A)	$	1,500	$	1,022	$	478	Mar 2024	Commercial Paper Support/Funding/Letters of Credit
Total PSEG	$	1,500	$	1,022	$	478
PSE&G
5-year Credit Facility (B)	$	600	$	18	$	582	Mar 2024	Commercial Paper Support/Funding/Letters of Credit
Total PSE&G	$	600	$	18	$	582
PSEG Power
3-year Letter of Credit Facility (C)	$	100	$	87	$	13	Sept 2023	Letters of Credit
5-year Credit Facilities (D)	1,900		58		1,842		Mar 2024	Funding/Letters of Credit
Total PSEG Power	$	2,000	$	145	$	1,855
Total	$	4,100	$	1,185	$	2,915

(A)PSEG facilities will be reduced by $9 million in March 2022.

(B)PSE&G facility will be reduced by $4 million in March 2022.

(C)In December 2021, PSEG Power extended its letter of credit facility for one year from September 2022 to September 2023.

(D)PSEG Power facilities will be reduced by $12 million in March 2022.

(E)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, 2021, PSEG had $1.0 billion outstanding at a weighted average interest rate of 0.33%. PSE&G had no Commercial Paper outstanding as of December 31, 2021.

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. In March 2021, each of PSEG and PSEG Power and its subsidiaries received waivers from the lenders and the administrative agent under their existing credit agreements permitting them to divest, in one or more transactions, some or all of its and its subsidiaries’ non-nuclear assets without breaching the terms of the agreements.

Short-Term Loans

PSEG

In August 2021, PSEG entered into a $1.25 billion, 364-day variable rate term loan agreement. In March and May 2021, PSEG entered into two 364-day variable rate term loan agreements for $500 million and $750 million, respectively. In March 2020, PSEG entered into a $300 million, 364-day variable rate term loan agreement which was prepaid in January 2021.

During the second half of 2021, PSEG Power experienced a substantial increase in net cash collateral postings related to hedge positions that are out-of-the-money due to an increase in energy market prices, from $343 million at the end of June to $844 million at the end of December. PSEG issued short-term borrowings, including commercial paper, in order to satisfy the increase in collateral postings and to prepare for the PSEG Power debt redemption. In October, PSEG Power borrowed $755 million from its credit facility to support its Senior Notes redemption and additional cash collateral postings, as needed. In November, PSEG issued $1.5 billion of Senior Notes, using a portion of the funds to provide support to PSEG Power for paying off the $755 million loan from the credit facility.

Fair Value of Debt

The estimated fair values, carrying amounts and methods used to determine fair value of long-term debt as of December 31, 2021 and 2020 are included in the following table and accompanying notes as of December 31, 2021 and 2020. See Note 19. Fair Value Measurements for more information on fair value guidance and the hierarchy that prioritizes the inputs to fair value measurements into three levels.

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	December 31, 2021				December 31, 2020
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	Millions
Long-Term Debt (A):
PSEG	$	4,124	$	4,172	$	2,929	$	3,092
PSE&G	11,795		13,374		10,909		13,372
PSEG Power (B)	—		—		2,342		2,679
Total Long-Term Debt	$	15,919	$	17,546	$	16,180	$	19,143

(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 that is based on a conventional discounted cash flow 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)In October 2021, PSEG redeemed all of PSEG Power’s outstanding Senior Notes.

Note 17. Schedule of Consolidated Capital Stock



	As of December 31,
	Outstanding Shares		Book Value
	2021	2020	2021		2020
	Millions
PSEG Common Stock (no par value) (A)
Authorized 1,000 shares	504	504	$	4,149	$	4,170

(A)PSEG did not issue any new shares under the Dividend Reinvestment and Stock Purchase Plan or the Employee Stock Purchase Plan (ESPP) in 2021 or 2020.

As of December 31, 2021, 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 18. Financial Risk Management Activities

Derivative accounting guidance requires that a derivative instrument be recognized as either an asset or a liability at fair value, with changes in fair value of the derivative recognized in earnings each period. Other accounting treatments are available through special election and designation provided that the derivative instrument meets specific, restrictive criteria, both at the time of designation and on an ongoing basis. These alternative permissible treatments include normal purchases and normal sales (NPNS), cash flow hedge and fair value hedge accounting. PSEG and PSE&G have applied the NPNS scope exception to certain derivative contracts for the forward sale of generation, power procurement agreements and fuel agreements. PSEG uses interest rate swaps and other derivatives, which are designated and 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, fossil fuels and other commodities. Fluctuations in market prices result from changes in supply and demand, fuel costs, market conditions, weather, state and federal regulatory policies, environmental policies, transmission availability and other factors. PSEG Power uses a variety of derivative and non-derivative instruments, such as financial options, futures, swaps, fuel purchases and forward purchases and sales of electricity, to manage the exposure to fluctuations in commodity prices and optimize the value of PSEG Power’s expected generation. PSEG Power also uses derivatives to hedge a portion of its anticipated BGSS obligations with PSE&G. For additional information see Note 15. Commitments and Contingent Liabilities. Changes in the fair market value of these derivative contracts are recorded in earnings.

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Interest Rates

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

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. There were no outstanding interest rate hedges as of December 31, 2021 and 2020.

The Accumulated Other Comprehensive Income (Loss) (after tax) related to outstanding and terminated interest rate derivatives designated as cash flow hedges was $(6) million and $(9) million as of December 31, 2021 and December 31, 2020, respectively. The after-tax unrealized losses 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 19. 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, 2021 and 2020. The following tabular disclosure does not include the offsetting of trade receivables and payables.



	As of December 31, 2021
	Not Designated
Balance Sheet Location	Energy- Related Contracts		Netting (A)		Total Derivatives
	Millions
Derivative Contracts
Current Assets	$	816	$	(744)	$	72
Noncurrent Assets	546		(518)		28
Total Mark-to-Market Derivative Assets	$	1,362	$	(1,262)	$	100
Derivative Contracts
Current Liabilities	$	(1,055)	$	1,038	$	(17)
Noncurrent Liabilities	(856)		839		(17)
Total Mark-to-Market Derivative (Liabilities)	$	(1,911)	$	1,877	$	(34)
Total Net Mark-to-Market Derivative Assets (Liabilities)	$	(549)	$	615	$	66

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	As of December 31, 2020
	Not Designated
Balance Sheet Location	Energy- Related Contracts		Netting (A)		Total Derivatives
	Millions
Derivative Contracts
Current Assets	$	464	$	(404)	$	60
Noncurrent Assets	93		(84)		9
Total Mark-to-Market Derivative Assets	$	557	$	(488)	$	69
Derivative Contracts
Current Liabilities	$	(412)	$	391	$	(21)
Noncurrent Liabilities	(109)		105		(4)
Total Mark-to-Market Derivative (Liabilities)	$	(521)	$	496	$	(25)
Total Net Mark-to-Market Derivative Assets (Liabilities)	$	36	$	8	$	44

(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, 2021 and 2020, PSEG Power had net cash collateral payments to counterparties of $844 million and $54 million, respectively. Of these net cash collateral (receipts) payments, $615 million as of December 31, 2021 and $8 million as of December 31, 2020 were netted against the corresponding net derivative contract positions. Of the $615 million as of December 31, 2021, $(30) million was netted against current assets, $(13) million was netted against non-current assets, $323 million was netted against current liabilities and $335 million was netted against noncurrent liabilities. Of the $8 million as of December 31, 2020, $(13) million was netted against current assets and $21 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 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 $75 million and $28 million as of December 31, 2021 and 2020, respectively. As of December 31, 2021 and 2020, PSEG Power had the contractual right of offset of $29 million and $3 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 $46 million and $25 million as of December 31, 2021 and 2020, 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, 2021, 2020 and 2019.

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	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,
	2021		2020		2019			2021		2020		2019
	Millions							Millions
Interest Rate Swaps	$	—	$	(6)	$	(23)	Interest Expense	$	(4)	$	(14)	$	(4)
Total	$	—	$	(6)	$	(23)		$	(4)	$	(14)	$	(4)

The effect of interest rate cash flow hedges is recorded in Interest Expense in PSEG’s Consolidated Statement of Operations. For the year ended December 31, 2021, the amount of loss on interest rate hedges reclassified from Accumulated Other Comprehensive Income (Loss) into income was $3 million, $10 million and $3 million after tax as of December 31, 2021, 2020 and 2019, 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, 2019	$	(21)	$	(15)
Loss Recognized in AOCI	(6)		(4)
Less: Loss Reclassified into Income	14		10
Balance as of December 31, 2020	$	(13)	$	(9)
Loss Recognized in AOCI	—		—
Less: Loss Reclassified into Income	4		3
Balance as of December 31, 2021	$	(9)	$	(6)

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, 2021, 2020 and 2019. PSEG Power’s derivative contracts reflected in this table include contracts to hedge the purchase and sale of electricity and natural gas, and the purchase of fuel. The table does not include contracts that PSEG Power has designated as NPNS, such as its BGS contracts and certain other energy supply contracts that it has with other utilities and companies with retail load.



Derivatives Not Designated as Hedges	Location of Pre-Tax Gain (Loss) Recognized in Income on Derivatives	Pre-Tax Gain (Loss) Recognized in Income on Derivatives
		Years Ended December 31,
		2021		2020		2019
		Millions
Energy-Related Contracts	Operating Revenues	$	993	$	279	$	560
Energy-Related Contracts	Energy Costs	(126)		(142)		(119)
Total		$	867	$	137	$	441

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The following table summarizes the net notional volume purchases/(sales) of open derivative transactions by commodity as of December 31, 2021 and 2020.



		As of December 31,
Type	Notional	2021	2020
		Millions
Natural Gas	Dekatherm (Dth)	47	321
Electricity	MWh	(76)	(66)
Financial Transmission Rights (FTRs)	MWh	27	20

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.

The following table provides information on PSEG Power’s credit risk from wholesale counterparties, net of collateral, as of December 31, 2021. It further delineates that exposure by the credit rating of the counterparties, which is determined by the lowest rating from S&P, Moody’s or an internal scoring model. In addition, it provides guidance on the concentration of credit risk to individual counterparties and an indication of the quality of PSEG Power’s credit risk by credit rating of the counterparties.

As of December 31, 2021, 99.8% of the net credit exposure for PSEG Power’s wholesale operations was with investment grade counterparties. Credit exposure is defined as any positive results of netting accounts receivable/accounts payable and the forward value of open positions (which includes all financial instruments including derivatives, NPNS and non-derivatives).



Rating	Current Exposure		Securities held as Collateral		Net Exposure		Number of Counterparties >10%	Net Exposure of Counterparties >10% (A)
	Millions							Millions
Investment Grade	$	356	$	185	$	171	1	$	143
Non-Investment Grade	2		1		1		—	—
Total	$	358	$	186	$	172	1	$	143

(A)Represents net exposure with PSE&G.

As of December 31, 2021, collateral held from counterparties where PSEG Power had credit exposure included $186 million in letters of credit.

As of December 31, 2021, PSEG Power had 106 active counterparties.

PSE&G’s supplier master agreements are approved by the BPU and govern the terms of its electric supply procurement contracts. These agreements define a supplier’s performance assurance requirements and allow a supplier to meet its credit requirements with a certain amount of unsecured credit. The amount of unsecured credit is determined based on the supplier’s credit ratings from the major credit rating agencies and the supplier’s tangible net worth. The credit position is based on the initial market price, which is the forward price of energy on the day the procurement transaction is executed, compared to the forward price curve for energy on the valuation day. To the extent that the forward price curve for energy exceeds the initial market price, the supplier is required to post a parental guaranty 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, 2021, PSEG held parental guaranties, letters of credit and cash as security. PSE&G’s BGS suppliers’ credit exposure is calculated each business day. As of December 31, 2021, PSE&G had credit exposure of $68 million with its suppliers. As of December 31, 2021, PSE&G had no net credit exposure with PSEG Power.

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 19. 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, PSE&G and PSEG Power have the ability to access. These consist primarily of listed equity securities and money market mutual funds, as well as natural gas futures contracts executed on NYMEX.

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

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

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

The following tables present information about PSEG’s and PSE&G’s respective assets and (liabilities) measured at fair value on a recurring basis as of December 31, 2021 and December 31, 2020, 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, 2021
Description	Total		Netting (D)		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)	$	615	$	—	$	615	$	—	$	—
Derivative Contracts:
Energy-Related Contracts (B)	$	100	$	(1,262)	$	25	$	1,336	$	1
NDT Fund (C)
Equity Securities	$	1,301	$	—	$	1,301	$	—	$	—
Debt Securities—U.S. Treasury	$	314	$	—	$	—	$	314	$	—
Debt Securities—Govt Other	$	373	$	—	$	—	$	373	$	—
Debt Securities—Corporate	$	647	$	—	$	—	$	647	$	—

Rabbi Trust (C)
Equity Securities	$	26	$	—	$	26	$	—	$	—
Debt Securities—U.S. Treasury	$	73	$	—	$	—	$	73	$	—
Debt Securities—Govt Other	$	34	$	—	$	—	$	34	$	—
Debt Securities—Corporate	$	109	$	—	$	—	$	109	$	—

Liabilities:
Derivative Contracts:
Energy-Related Contracts (B)	$	(34)	$	1,877	$	(26)	$	(1,880)	$	(5)

PSE&G
Assets:
Cash Equivalents (A)	$	250	$	—	$	250	$	—	$	—


Rabbi Trust (C)
Equity Securities	$	5	$	—	$	5	$	—	$	—
Debt Securities—U.S. Treasury	$	13	$	—	$	—	$	13	$	—
Debt Securities—Govt Other	$	6	$	—	$	—	$	6	$	—
Debt Securities—Corporate	$	19	$	—	$	—	$	19	$	—

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	Recurring Fair Value Measurements as of December 31, 2020
Description	Total		Netting (D)		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)	$	312	$	—	$	312	$	—	$	—
Derivative Contracts:
Energy-Related Contracts (B)	$	69	$	(488)	$	26	$	519	$	12

NDT Fund (C)
Equity Securities	$	1,352	$	—	$	1,351	$	1	$	—
Debt Securities—U.S. Treasury	$	239	$	—	$	—	$	239	$	—
Debt Securities—Govt Other	$	342	$	—	$	—	$	342	$	—
Debt Securities—Corporate	$	566	$	—	$	—	$	566	$	—

Rabbi Trust (C)
Equity Securities	$	31	$	—	$	31	$	—	$	—
Debt Securities—U.S. Treasury	$	59	$	—	$	—	$	59	$	—
Debt Securities—Govt Other	$	41	$	—	$	—	$	41	$	—
Debt Securities—Corporate	$	135	$	—	$	—	$	135	$	—

Liabilities:
Derivative Contracts:
Energy-Related Contracts (B)	$	(25)	$	496	$	(33)	$	(483)	$	(5)

PSE&G
Assets:
Cash Equivalents (A)	$	50	$	—	$	50	$	—	$	—


Rabbi Trust (C)
Equity Securities	$	6	$	—	$	6	$	—	$	—
Debt Securities—U.S. Treasury	$	11	$	—	$	—	$	11	$	—
Debt Securities—Govt Other	$	8	$	—	$	—	$	8	$	—
Debt Securities—Corporate	$	26	$	—	$	—	$	26	$	—

(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” below for more information on the utilization of unobservable inputs.

(C)As of each of December 31, 2021 and 2020, the fair value measurement table excludes foreign currency of $2 million 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).

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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 preferred stocks are not actively traded on a daily basis and therefore, are also priced using an evaluated pricing methodology. Certain short-term investments are valued using observable market prices or market parameters such as time-to-maturity, coupon rate, quality rating and current yield.

(D)Represents the netting of fair value balances with the same counterparty (where the right of offset exists) and the application of collateral. See Note 18. 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, 2021, PSEG carried $3.6 billion of net assets that were measured at fair value on a recurring basis, of which $4 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, 2020, PSEG carried $3.1 billion of net assets that were measured at fair value on a recurring basis, of which $7 million of net assets were measured using unobservable inputs and classified as Level 3 within the fair value hierarchy and are considered immaterial.

There were no transfers in 2021 and 2020 to or from Level 3.

Note 20. 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 ((LTIP 2004) 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, restricted stock, restricted stock units, 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.

The 2021 LTIP currently provides for the issuance of equity awards with respect to 8 million shares of common stock. As of December 31, 2021, approximately 8 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.

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Under the 2021 BOD Plan, the only equity instrument which may be granted are Restricted Stock Units (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. Option awards are granted with an exercise price equal to the market price of PSEG’s common stock at the grant date. The options generally vest over four years of continuous service. Vesting schedules may be accelerated upon the occurrence of certain events, such as a change-in-control (unless substituted with an equity award of equal value), retirement, death or disability. Options are exercisable over a period of time designated by the O&CC (but not prior to one year or longer than ten years from the date of grant) and are subject to such other terms and conditions as the O&CC determines. Payment by option holders upon exercise of an option may be made in cash or, with the consent of the O&CC, by delivering previously acquired shares of PSEG common stock. 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 2021 and 2020 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.

Performance Share Units (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 financial goals over a three-year performance period. 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 certain financial targets, including targets related to comparative performance against other companies in a peer group of energy companies. 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 stock options based on their grant date fair values, which are determined using the Black-Scholes option-pricing model. Stock option awards are expensed on a tranche-specific basis over the requisite service period of the award. Ultimately, compensation expense for stock options is recognized for awards that vest.

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 2021, 2020 and 2019:



Grant Date	Risk-Free Interest Rate	Volatility

February 16, 2021	0.22%	27.31%
February 18, 2020	1.36%	15.00%
February 19, 2019	2.47%	16.74%

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 the return on invested capital target for 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.

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	2021		2020		2019
	Millions
Compensation Cost included in O&M Expense	$	28	$	35	$	33
Income Tax Benefit Recognized in Consolidated Statement of Operations	$	8	$	10	$	9

For 2021, 2020 and 2019, PSEG also recorded excess tax benefits of $2 million, $2 million and $5 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.

Stock Options

As of January 1, 2019, there were 231,933 stock options outstanding, all of which were exercised in 2019 at a weighted average price of $33.49. There were no stock options granted or vested in 2021, 2020 and 2019.

Activity for options exercised for the years ended December 31, 2021, 2020 and 2019 is shown below:



	2021		2020		2019
	Millions
Total Intrinsic Value of Options Exercised	$	—	$	—	$	5
Cash Received from Options Exercised	$	—	$	—	$	8
Tax Benefit Realized from Options Exercised	$	—	$	—	$	1

RSUs

Changes in RSUs for the year ended December 31, 2021 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, 2021	222,898	$	54.21
Granted	239,249	$	58.02
Vested	268,423	$	55.00
Canceled/Forfeited	13,893	$	57.80
Non-vested as of December 31, 2021	179,831	$	57.83	1.2	$	12,000,123

The weighted average grant date fair value per share for RSUs during the years ended December 31, 2021, 2020 and 2019 was $58.02, $58.85 and $56.24 per share, respectively.

The total intrinsic value of RSUs distributed during the years ended December 31, 2021, 2020 and 2019 was $17 million, $11 million and $16 million, respectively.

As of December 31, 2021, there was approximately $4 million of unrecognized compensation cost related to the RSUs, which is expected to be recognized over a weighted average period of 1.1 years. DEUs of 21,801 accrued on the RSUs during the year.

PSUs

Changes in PSUs for the year ended December 31, 2021 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, 2021	475,841	$	54.88
Granted	373,418	$	65.57
Vested	337,332	$	59.49
Canceled/Forfeited	35,573	$	58.08
Non-vested as of December 31, 2021	476,354	$	59.76	1.6	$	31,787,102

The weighted average grant date fair value per share for PSUs during the years ended December 31, 2021, 2020 and 2019 was $65.57, $51.79 and $62.17 per share, respectively.

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The total intrinsic value of PSUs distributed during the years ended December 31, 2021, 2020 and 2019 was $28 million, $19 million and $17 million, respectively.

As of December 31, 2021, there was approximately $23 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 37,371 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 immaterial for each of the years ended December 31, 2021, 2020 and 2019.

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 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 the year ended December 31, 2021 and $1 million for each of the years ended December 31, 2020 and 2019.

During the years ended December 31, 2021, 2020 and 2019, employees purchased 326,634 shares, 373,682 shares and 280,077 shares, respectively, at an average price of $56.87, $47.26 and $54.67 per share, respectively. As of December 31, 2021, 1.9 million shares were available for future issuance under this plan.

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Note 21. Other Income (Deductions)



	PSE&G		Other (A)		Consolidated Total
	Millions
Year Ended December 31, 2021
NDT Fund Interest and Dividends	$	—	$	59	$	59
Allowance for Funds Used During Construction	71		—		71
Solar Loan Interest	13		—		13
Donations	(1)		(21)		(22)
Purchase of Tax Losses under New Jersey Technology Tax Benefit Transfer Program	—		(19)		(19)
Other	5		(9)		(4)
Total Other Income (Deductions)	$	88	$	10	$	98
Year Ended December 31, 2020
NDT Fund Interest and Dividends	$	—	$	52	$	52
Allowance for Funds Used During Construction	87		—		87
Solar Loan Interest	15		—		15
Donations	—		(3)		(3)
Purchase of Tax Losses under New Jersey Technology Tax Benefit Transfer Program	—		(36)		(36)
Other	6		(6)		—
Total Other Income (Deductions)	$	108	$	7	$	115
Year Ended December 31, 2019
NDT Fund Interest and Dividends	$	—	$	57	$	57
Allowance for Funds Used During Construction	59		—		59
Solar Loan Interest	16		—		16
Donations	—		(11)		(11)
Other	8		(4)		4
Total Other Income (Deductions)	$	83	$	42	$	125

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

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Note 22. 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	2021			2020			2019
	Millions
Net Income (Loss)	$	(648)		$	1,905		$	1,693
Income Taxes:
Operating Income:
Current (Benefit) Expense:
Federal	$	407		$	385		$	84
State	(3)			48			18
Total Current	404			433			102
Deferred Expense (Benefit):
Federal	(700)			(164)			3
State	(136)			141			132
Total Deferred	(836)			(23)			135
ITC	(9)			(14)			20
Total Income Tax Expense (Benefit)	$	(441)		$	396		$	257
Pre-Tax Income (Loss)	$	(1,089)		$	2,301		$	1,950
Tax Computed at Statutory Rate @ 21%	$	(229)		$	483		$	410
Increase (Decrease) Attributable to Flow-Through of Certain Tax Adjustments:
State Income Taxes (net of federal income tax)	(109)			147			117
Uncertain Tax Positions	19			3			—
NDT Fund	23			32			34
Plant-Related Items	(7)			(9)			(2)
Tax Credits	29			(18)			(18)
Audit Settlement	(8)			(27)			—
Leasing Activities	(1)			(35)			—
GPRC-CEF-EE	(13)			—			—
TAC	(171)			(205)			(272)
Bad Debt Flow-Through	27			28			—
Other	(1)			(3)			(12)
Subtotal	(212)			(87)			(153)
Total Income Tax Expense (Benefit)	$	(441)		$	396		$	257
Effective Income Tax Rate	40.5		%	17.2		%	13.2		%

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The following is an analysis of deferred income taxes for PSEG:



	As of December 31,
PSEG	2021		2020
	Millions
Deferred Income Taxes
Assets:
Noncurrent:
Regulatory Liability Excess Deferred Tax	$	439	$	485
OPEB	107		135
Bad Debt	67		40
Related to Uncertain Tax Positions	30		29
Interest Disallowance Carryforward	—		39
Operating Leases	48		60
Other	253		130
Total Noncurrent Assets	$	944	$	918

Liabilities:
Noncurrent:
Plant-Related Items	$	4,701	$	5,163
New Jersey Corporate Business Tax	939		1,016
Leasing Activities	113		133
AROs and NDT Fund	270		324
Taxes Recoverable Through Future Rates (net)	120		114
Pension Costs	169		97
Operating Leases	43		55
Other	271		247
Total Noncurrent Liabilities	$	6,626	$	7,149
Summary of Accumulated Deferred Income Taxes:
Net Noncurrent Deferred Income Tax Liabilities	$	5,682	$	6,231
ITC	77		271
Net Total Noncurrent Deferred Income Taxes and ITC	$	5,759	$	6,502

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	2021			2020			2019
	Millions
Net Income	$	1,446		$	1,327		$	1,250
Income Taxes:
Operating Income:
Current (Benefit) Expense:
Federal	$	208		$	179		$	121
State	1			8			—
Total Current	209			187			121
Deferred Expense (Benefit):
Federal	(33)			(71)			(156)
State	153			128			117
Total Deferred	120			57			(39)
ITC	(5)			(4)			11
Total Income Tax Expense	$	324		$	240		$	93
Pre-Tax Income	$	1,770		$	1,567		$	1,343
Tax Computed at Statutory Rate @ 21%	$	372		$	329		$	282
Increase (Decrease) Attributable to Flow-Through of Certain Tax Adjustments:
State Income Taxes (net of federal income tax)	122			106			92
Uncertain Tax Positions	2			4			1
Plant-Related Items	(7)			(9)			(2)
Tax Credits	(8)			(9)			(8)
Audit Settlement	(1)			(2)			—
GPRC-CEF-EE	(13)			—			—
TAC	(171)			(205)			(272)
Bad Debt Flow-Through	27			28			—
Other	1			(2)			—
Subtotal	(48)			(89)			(189)
Total Income Tax Expense	$	324		$	240		$	93
Effective Income Tax Rate	18.3		%	15.3		%	6.9		%

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The following is an analysis of deferred income taxes for PSE&G:



	As of December 31,
PSE&G	2021		2020
	Millions
Deferred Income Taxes
Assets:
Noncurrent:
Regulatory Liability Excess Deferred Tax	$	439	$	485
OPEB	61		82
Bad Debt	67		40
Operating Leases	20		21
Other	57		52
Total Noncurrent Assets	$	644	$	680
Liabilities:
Noncurrent:
Plant-Related Items	$	4,006	$	3,874
New Jersey Corporate Business Tax	863		721
Pension Costs	180		166
Taxes Recoverable Through Future Rates (net)	120		114
Conservation Costs	75		61
Operating Leases	19		21
Related to Uncertain Tax Positions	1		5
Other	178		161
Total Noncurrent Liabilities	$	5,442	$	5,123
Summary of Accumulated Deferred Income Taxes:
Net Noncurrent Deferred Income Tax Liabilities	$	4,798	$	4,443
ITC	76		81
Net Total Noncurrent Deferred Income Taxes and ITC	$	4,874	$	4,524

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 7. 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, 2020, the balance was approximately $1.7 billion with a Regulatory Liability of approximately $2.4 billion. In 2021, PSE&G returned approximately $238 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 $171 million. The flowback to customers of the excess deferred income taxes and previously realized tax repair deductions resulted in a decrease of approximately $215 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 7. 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.

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In April 2020, the IRS issued a private letter ruling (PLR) 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 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.

PSEG expects that a prolonged economic recovery may result in additional federal or state tax legislation that can have a material impact on PSEG’s and PSE&G’s tax expense and cash tax position.

Amounts recorded under the Tax Act and CARES Act are subject to change based on several factors, including whether the IRS or state taxing authorities issue additional guidance and/or further clarification. Any further guidance or clarification could impact PSEG’s and PSE&G’s financial statements.

As of December 31, 2021, PSE&G had a $15 million New Jersey Corporate Business Tax NOL that is expected to be fully realized in the future. There are no other material tax carryforwards in other jurisdictions.

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:



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

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2020	PSEG		PSE&G
	Millions
Total Amount of Unrecognized Tax Benefits as of January 1, 2020	$	321	$	124
Increases as a Result of Positions Taken in a Prior Period	33		21
Decreases as a Result of Positions Taken in a Prior Period	(91)		(51)
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	(116)		(64)
Decreases due to Lapses of Applicable Statute of Limitations	—		—
Total Amount of Unrecognized Tax Benefits as of December 31, 2020	$	147	$	30
Accumulated Deferred Income Taxes Associated with Unrecognized Tax Benefits	(69)		(12)
Regulatory Asset—Unrecognized Tax Benefits	(15)		(15)
Total Amount of Unrecognized Tax Benefits that if Recognized, would Impact the Effective Tax Rate (including Interest and Penalties)	$	63	$	3

In April 2020, the Joint Committee on Taxation approved PSEG’s nuclear carryback claim and federal tax returns for the years 2011 and 2012. In June 2020, the federal income tax audits for years 2011 through 2016 and the nuclear carryback claim were concluded.



2019	PSEG		PSE&G
	Millions
Total Amount of Unrecognized Tax Benefits as of January 1, 2019	$	318	$	108
Increases as a Result of Positions Taken in a Prior Period	17		5
Decreases as a Result of Positions Taken in a Prior Period	(37)		(1)
Increases as a Result of Positions Taken during the Current Period	27		12
Decreases as a Result of Positions Taken during the Current Period	—		—
Decreases as a Result of Settlements with Taxing Authorities	(4)		—
Decreases due to Lapses of Applicable Statute of Limitations	—		—
Total Amount of Unrecognized Tax Benefits as of December 31, 2019	$	321	$	124
Accumulated Deferred Income Taxes Associated with Unrecognized Tax Benefits	(184)		(71)
Regulatory Asset—Unrecognized Tax Benefits	(46)		(46)
Total Amount of Unrecognized Tax Benefits that if Recognized, would Impact the Effective Tax Rate (including Interest and Penalties)	$	91	$	7

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,
	2021		2020		2019
	Millions
PSEG	$	31	$	29	$	40
PSE&G	$	9	$	9	$	16

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:

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Possible Decrease in Total Unrecognized Tax Benefits	Over the next 12 Months
	Millions
PSEG	$	25
PSE&G	$	15

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

2017-2020

N/A

New Jersey

2011-2020

Pennsylvania

2017-2020

2018-2020

Connecticut

2018-2020

N/A

Maryland

2018-2020

N/A

New York

2017-2020

N/A

New Jersey State Tax Reform

In September 2020, New Jersey enacted its State Fiscal Year 2021 Budget, which amended the temporary surtax originally enacted into law in 2018, from 1.5% to 2.5% for 2020 and 2021 and extended the 2.5% surtax to 2023. PSE&G continues to be exempt and this amendment will not have a material impact on PSEG’s and PSEG Power’s financial statements.

Note 23. 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, 2018	$	(1)	$	(360)	$	(16)	$	(377)
Cumulative Effect Adjustment to Reclassify Stranded Tax Effects Resulting in the Change in the Federal Corporate Income Tax to Retained Earnings	—		(81)		—		(81)
Current Period Other Comprehensive Income (Loss)
Other Comprehensive Income (Loss) before Reclassifications	(17)		(70)		49		(38)
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	3		12		(8)		7
Net Current Period Other Comprehensive Income (Loss)	(14)		(58)		41		(31)
Net Change in Accumulated Other Comprehensive Income (Loss)	(14)		(139)		41		(112)
Balance as of December 31, 2019	$	(15)	$	(499)	$	25	$	(489)
Other Comprehensive Income (Loss) before Reclassifications	(4)		(58)		51		(11)
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	10		12		(26)		(4)
Net Current Period Other Comprehensive Income (Loss)	6		(46)		25		(15)
Balance as of December 31, 2020	$	(9)	$	(545)	$	50	$	(504)
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)

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PSEG		Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement
		Year Ended December 31, 2019
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 Swaps	Interest Expense	$	(4)	$	1	$	(3)
Total Cash Flow Hedges		(4)		1		(3)
Pension and OPEB Plans
Amortization of Prior Service (Cost) Credit	Non-Operating Pension and OPEB Credits (Costs)	26		(7)		19
Amortization of Actuarial Loss	Non-Operating Pension and OPEB Credits (Costs)	(43)		12		(31)
Total Pension and OPEB Plans		(17)		5		(12)
Available-for-Sale Securities
Realized Gains (Losses)	Net Gains (Losses) on Trust Investments	13		(5)		8
Total Available-for-Sale Securities		13		(5)		8
Total		$	(8)	$	1	$	(7)




PSEG		Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement
		Year Ended December 31, 2020
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 Swaps	Interest Expense	$	(14)	$	4	$	(10)
Total Cash Flow Hedges		(14)		4		(10)
Pension and OPEB Plans
Amortization of Prior Service (Cost) Credit	Non-Operating Pension and OPEB Credits (Costs)	24		(7)		17
Amortization of Actuarial Loss	Non-Operating Pension and OPEB Credits (Costs)	(40)		11		(29)
Total Pension and OPEB Plans		(16)		4		(12)
Available-for-Sale Securities
Realized Gains (Losses) and Impairments	Net Gains (Losses) on Trust Investments	42		(16)		26
Total Available-for-Sale Securities		42		(16)		26
Total		$	12	$	(8)	$	4

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PSEG		Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement
		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 Swaps	Interest Expense	$	(4)	$	1	$	(3)
Total Cash Flow Hedges		(4)		1		(3)
Pension and OPEB Plans
Amortization of Prior Service (Cost) Credit	Non-Operating Pension and OPEB Credits (Costs)	21		(6)		15
Amortization of Actuarial Loss	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)

Note 24. 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 20. 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,
	2021				2020				2019
	Basic		Diluted		Basic		Diluted		Basic		Diluted
EPS Numerator:
(Millions)
Net Income (Loss)	$	(648)	$	(648)	$	1,905	$	1,905	$	1,693	$	1,693
EPS Denominator:
(Millions)
Weighted Average Common Shares Outstanding	504		504		504		504		504		504
Effect of Stock Based Compensation Awards	—		—		—		3		—		3
Total Shares	504		504		504		507		504		507
EPS:
Net Income (Loss)	$	(1.29)	$	(1.29)	$	3.78	$	3.76	$	3.35	$	3.33

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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.

For additional information on all the types of long-term incentive awards, see Note 20. Stock Based Compensation.

Dividends



	Years Ended December 31,
Dividend Payments on Common Stock	2021		2020		2019
Per Share	$	2.04	$	1.96	$	1.88
in Millions	$	1,031	$	991	$	950

On February 15, 2022, PSEG’s Board of Directors approved a $0.54 per share common stock dividend for the first quarter of 2022.

Note 25. 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 management measures performance based on segment Net Income, as illustrated in the following table, and how resources are allocated to each business. PSEG’s reportable segments are PSE&G and PSEG Power. PSE&G represents a single reportable segment and therefore no separate segment information is provided for PSE&G.

PSE&G

PSE&G earns revenues from its tariffs, under which it provides electric transmission and electric and gas distribution services to residential, C&I 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 energy efficiency equipment on customers’ premises, solar investments, the appliance service business and other miscellaneous services.

PSEG Power

PSEG Power earns revenues primarily by bidding energy, capacity and ancillary services into the markets for these products and by selling energy, capacity and ancillary services on a wholesale basis under contract to power marketers and to load-serving entities. A significant portion of PSEG Power’s revenue is obtained from the various ISOs in which PSEG Power operates. The ISOs act similarly to a clearing house for all of its members in that all revenues paid out are collected from market participants based on their consumption of energy and energy-related products. PSEG Power also enters into bilateral contracts for energy, capacity, FTRs, gas, emission allowances and other energy-related contracts to optimize the value of its portfolio of generating assets and its electric and gas supply obligations. In addition, PSEG Power’s Salem 1, Salem 2 and Hope Creek nuclear plants receive ZEC revenue from the EDCs in New Jersey including PSE&G.

Other

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

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	PSE&G		PSEG Power		Other (A)		Eliminations (B)		Consolidated Total
	Millions
Year Ended December 31, 2021
Operating Revenues	$	7,122	$	3,147	$	620	$	(1,167)	$	9,722
Depreciation and Amortization	928		256		32		—		1,216
Operating Income (Loss)	1,818		(2,711)		37		—		(856)
Income from Equity Method Investments	—		16		—		—		16
Interest Income	14		2		8		(4)		20
Interest Expense	402		78		95		(4)		571
Income (Loss) before Income Taxes	1,770		(2,808)		(51)		—		(1,089)
Income Tax Expense (Benefit)	324		(752)		(13)		—		(441)
Net Income (Loss) (C) (D)	$	1,446	$	(2,056)	$	(38)	$	—	$	(648)
Gross Additions to Long-Lived Assets	$	2,447	$	259	$	13	$	—	$	2,719
As of December 31, 2021
Total Assets	$	37,198	$	9,777	$	5,150	$	(3,126)	$	48,999
Investments in Equity Method Subsidiaries	$	—	$	62	$	111	$	—	$	173



	PSE&G		PSEG Power		Other (A)		Eliminations (B)		Consolidated Total
	Millions
Year Ended December 31, 2020
Operating Revenues	$	6,608	$	3,634	$	595	$	(1,234)	$	9,603
Depreciation and Amortization	887		368		30		—		1,285
Operating Income (Loss)	1,639		603		28		—		2,270
Income from Equity Method Investments	—		14		—		—		14
Interest Income	17		6		5		(3)		25
Interest Expense	388		121		94		(3)		600
Income (Loss) before Income Taxes	1,567		782		(48)		—		2,301
Income Tax Expense (Benefit)	240		188		(32)		—		396
Net Income (Loss) (C) (D)	$	1,327	$	594	$	(16)	$	—	$	1,905
Gross Additions to Long-Lived Assets	$	2,507	$	404	$	12	$	—	$	2,923
As of December 31, 2020
Total Assets	$	35,581	$	12,704	$	2,692	$	(927)	$	50,050
Investments in Equity Method Subsidiaries	$	—	$	64	$	—	$	—	$	64

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	PSE&G		PSEG Power		Other (A)		Eliminations (B)		Consolidated Total
	Millions
Year Ended December 31, 2019
Operating Revenues	$	6,625	$	4,385	$	549	$	(1,483)	$	10,076
Depreciation and Amortization	837		377		34		—		1,248
Operating Income (Loss)	1,469		448		26		—		1,943
Income from Equity Method Investments	—		14		—		—		14
Interest Income	18		7		6		(5)		26
Interest Expense	361		119		94		(5)		569
Income (Loss) before Income Taxes	1,343		671		(64)		—		1,950
Income Tax Expense (Benefit)	93		203		(39)		—		257
Net Income (Loss) (C) (D)	$	1,250	$	468	$	(25)	$	—	$	1,693
Gross Additions to Long-Lived Assets	$	2,542	$	607	$	17	$	—	$	3,166
As of December 31, 2019
Total Assets	$	33,266	$	12,805	$	2,715	$	(1,056)	$	47,730
Investments in Equity Method Subsidiaries	$	—	$	66	$	1	$	—	$	67

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

(B)Intercompany eliminations 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 26. Related-Party Transactions.

(C)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. Includes an after-tax gain of $86 million in the year ended December 31, 2020 related to the sale of PSEG Power’s interest in the Yards Creek generation facility and an after-tax loss of $286 million in the year ended December 31, 2019 related to the sale of PSEG Power’s ownership interests in the Keystone and Conemaugh fossil generation plants. See Note 4. Early Plant Retirements/Asset Dispositions and Impairments for additional information.

(D)Includes net after-tax losses of $446 million and $58 million in the years ended December 31, 2021 and 2020 and a net after-tax gain of $205 million in the year ended December 31, 2019 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.

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Note 26. 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	2021		2020		2019
	Millions
Billings from Affiliates:
Net Billings from PSEG Power (A)	$	1,144	$	1,207	$	1,512
Administrative Billings from Services (B)	394		337		310
Total Billings from Affiliates	$	1,538	$	1,544	$	1,822



	Years Ended December 31,
Related Party Transactions	2021		2020
	Millions

Payable to PSEG Power (A)	$	244	$	273
Payable to Services (B)	111		95
Payable to PSEG (C)	63		111
Accounts Payable—Affiliated Companies	$	418	$	479
Working Capital Advances to Services (D)	$	33	$	33
Long-Term Accrued Taxes Payable	$	6	$	7

(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. PSEG Power has also entered into contracts to supply energy, capacity and ancillary services to PSE&G through the BGS auction process and sells ZECs to PSE&G under the ZEC program. 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 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, 2021, 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 165 and 166, 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 167. Management has concluded that internal control over financial reporting is effective as of December 31, 2021.

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 2021 that have materially affected, or are reasonably likely to materially affect, each registrant’s internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

None.

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, 2021 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, 2021.

PSEG’s external auditors, Deloitte & Touche LLP, have audited PSEG’s financial statements for the year ended December 31, 2021 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 IZZO
Chief Executive Officer

/s/ DANIEL J. CREGG
Chief Financial Officer
February 24, 2022

165

Table of Contents

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, 2021 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, 2021.



/s/ RALPH IZZO
Chief Executive Officer

/s/ DANIEL J. CREGG
Chief Financial Officer
February 24, 2022

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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”) as of December 31, 2021, 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, 2021, 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, 2021 of the Company and our report dated February 24, 2022 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

Parsippany, New Jersey

February 24, 2022

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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 2022 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 10, 2022 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 2021, 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 2022 Annual Meeting of Stockholders which definitive Proxy Statement is expected to be filed with the SEC on or about March 10, 2022 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 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 2022 Annual Meeting of Stockholders which definitive Proxy Statement is expected to be filed with the SEC on or about March 10, 2022 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 2022 Annual Meeting of Stockholders which definitive Proxy Statement is expected to be filed with the SEC on or about March 10, 2022 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 2021 and 2020” in PSEG’s definitive Proxy Statement for the 2022 Annual Meeting of Stockholders which definitive Proxy Statement is expected to be filed with the SEC on or about March 10, 2022. 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, 2021 and 2020 and the related Consolidated Statements of Operations, Comprehensive Income, Cash Flows and Stockholders’ Equity for the three years ended December 31, 2021 on pages 70 through 75.

b.Public Service Electric and Gas Company’s Consolidated Balance Sheets as of December 31, 2021 and 2020 and the related Consolidated Statements of Operations, Comprehensive Income, Cash Flows and Common Stockholder’s Equity for the three years ended December 31, 2021 on pages 76 through 81.

(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, 2021 (page 175).

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, 2021 (page 175).

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 December 15, 2015(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)		Deferred Compensation Plan for Certain Employees, amended and restated effective January 1, 2019(12)
10a(6)		Senior Management Incentive Compensation Plan(13)

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	LIST OF EXHIBITS:
10a(7)		Key Executive Severance Plan of Public Service Enterprise Group Incorporated, amended effective Ju ne 30 , 20 21(14)
10a(8)		Severance Agreement with Ralph Izzo dated December 16, 2008(15)
10a(9)		Stock Plan for Outside Directors, as amended(16)
10a(10)		Compensation Plan for Outside Directors(17)
10a(11)		20 04 Long-Term Incentive Plan, amende d and restate d as of A pril 16,2013(18)
10a(12)		Form of Agreement for Advancement of Expenses with Outside Directors(19)
10a(13)		Equity Deferral Plan, amended effective Oct ober 21, 2021(20)
10a(14)		Agreement with Tamara L. Linde dated June 18, 2014(21)
10a(15)		Agreement with Daniel J. Cregg dated September 22, 2015(22)
10a(16)		Clawback Practice, effective February 20, 2018(23)
10a(17)		Agreement with Ralph A. LaRossa dated December 16, 2019(24)
10a(18)		2021 Long-Term Incentive Plan, effective April 20, 2021(25)
10a(19)		2021 Equity Compensation Plan for Outside Directors, effective April 20, 2021(26)
10a(20)		Agreement with Kim C. Hanemann dated May 21, 2021(27)
10a(21 )		Agreement with David M. Daly dated Jan uary 3 , 202 2
21		Subsidiaries of the Registrant
23		Consent of Independent Registered Public Accounting Firm
31		Certification by Ralph Izzo, 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 Izzo, 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
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(28)
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(29)
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(30)
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(31)
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(32)
3b(1)		By-Laws of PSE&G as in effect April 17, 2007(33)
4a(1)		Indenture between PSE&G and Fidelity Union Trust Company (now, Wachovia Bank, National Association), as Trustee, dated August 1, 1924(34), 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(35)
4a(3)		July 1, 1937(36)
4a(4)		June 1, 1991 (No. 1)(37)
4a(5)		August 1, 2004 (No. 4)(38)
4a(6)		April 1, 2007(39)
4a(7)		November 1, 2009(40)
4a(8)		May 1, 2012(41)
4a(9)		May 1, 2013(42)
4a(10)		August 1, 2014(43)
4a(11)		May 1, 2015(44)
4a(12)		September 1, 2016(45)
4a(13)		April 1, 2018(46)
4a(14)		December 1, 2019(4 7 )
4b		Description of the First and Refunding Mortgage Bonds(4 8 )
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(49)
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(50)
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)		Deferred Compensation Plan for Certain Employees, amended and restated effective January 1, 2019(12)
10a(6)		Senior Management Incentive Compensation Plan(13)
10a(7)		Key Executive Severance Plan of Public Service Enterprise Group Incorporated, amended effective June 30, 2021(14)
10a(8)		Severance Agreement with Ralph Izzo dated December 16, 2008(15)
10a(9)		Stock Plan for Outside Directors, as amended(16)
10a(10)		Compensation Plan for Outside Directors(17)
10a(11)		2004 Long-Term Incentive Plan, amended and restated as of April 16,2013(18)
10a(12)		Form of Agreement for Advancement of Expenses with Outside Directors(51)
10a(13)		Equity Deferral Plan, amended effective October 21, 2021(20)
10a(14)		Agreement with Tamara L. Linde dated June 18, 2014(21)
10a(15)		Agreement with Daniel J. Cregg dated September 22, 2015(22)
10a(16)		Clawback Practice, effective February 20, 2018(23)
10a(18)		2021 Long-Term Incentive Plan, effective April 20, 2021(25)
10a(19)		2021 Equity Compensation Plan for Outside Directors, effective April 20, 2021(26)
10a(20)		Agreement with Kim C. Hanemann dated May 21, 2021(27)
10a(21 )		Agreement with David M. Daly dated January 3, 2022
23a		Consent of Independent Registered Public Accounting Firm
31b		Certification by Ralph Izzo, 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 Izzo, 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

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	LIST OF EXHIBITS:
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 99.1 with Current Report on Form 8-K, File No. 001-09120, on December 16, 2015 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 10a(5) 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.

(13)Filed as Exhibit 10a(11) with Annual Report on Form 10-K for the year ended December 31, 2008, File No. 001-09120, on February 26, 2009 and incorporated herein by this reference.

(14)Filed as Exhibit 10(1) 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.

(15)Filed as Exhibit 99 with Current Report on Form 8-K, File Nos. 001-09120, on December 22, 2008 and incorporated herein by this reference.

(16)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.

(17)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.

(18)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.

(19)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.

(20)Filed as Exhibit 10 with Quarterly Report on Form 10-Q for the quarter ended September 30, 2021, File No. 001-09120, on November 2, 2021 and incorporated herein by this reference.

(21)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.

(22)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.

(23)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.

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(24)Filed as Exhibit 10a(19) 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.

(25)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.

(26)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.

(27)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.

(28)Filed as Exhibit 3a(1) on Form 8-A, File No. 001-00973, on February 4, 1994 and incorporated herein by this reference.

(29)Filed as Exhibit 3a(2) on Form 8-A, File No. 001-00973, on February 4, 1994 and incorporated herein by this reference.

(30)Filed as Exhibit 3a(3) on Form 8-A, File No. 001-00973, on February 4, 1994 and incorporated herein by this reference.

(31)Filed as Exhibit 3a(4) on Form 8-A, File No. 001-00973, on February 4, 1994 and incorporated herein by this reference.

(32)Filed as Exhibit 3a(5) on Form 8-A, File No. 001-00973, on February 4, 1994 and incorporated herein by this reference.

(33)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.

(34)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.

(35)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.

(36)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.

(37)Filed as Exhibit 4(i) on Form 8-A, File No. 001-00973, on June 1, 1991 and incorporated herein by this reference.

(38)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.

(39)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.

(40)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.

(41)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.

(42)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.

(43)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.

(44)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.

(45)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.

(46)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.

(47)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.

(48)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.

(49)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.

(50)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.

(51)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, 2021—December 31, 2019

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
2021
Allowance for Credit Losses	$	206		$	195	(A)	$	—	$	64	(B)	$	337
Materials and Supplies Valuation Reserve	10			3			—		1		(C)	12
2020
Allowance for Credit Losses	$	68	(D)	$	175	(A)	$	—	$	37	(B)	$	206
Materials and Supplies Valuation Reserve	11			1			—		2		(C)	10
2019
Allowance for Credit Losses	$	63		$	87	(A)	$	—	$	90	(B)	$	60
Materials and Supplies Valuation Reserve	9			3			—		1		(C)	11

(A)For a discussion of bad debt recoveries, see Note 1. Organization, Basis of Presentation and Summary of Significant Accounting Policies.

(B)Accounts Receivable written off.

(C)Reduce reserve to appropriate level and to remove obsolete inventory.

(D)Includes $8 million due to the adoption of ASU 2016-13.

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
2021
Allowance for Credit Losses	$	206		$	195	(A)	$	—	$	64	(B)	$	337
Materials and Supplies Valuation Reserve	2			2			—		1		(C)	3
2020
Allowance for Credit Losses	$	68	(D)	$	175	(A)	$	—	$	37	(B)	$	206
Materials and Supplies Valuation Reserve	2			—			—		—			2
2019
Allowance for Credit Losses	$	63		$	87	(A)	$	—	$	90	(B)	$	60
Materials and Supplies Valuation Reserve	2			—			—		—			2

(A)For a discussion of bad debt recoveries, see Note 1. Organization, Basis of Presentation and Summary of Significant Accounting Policies.

(B)Accounts Receivable written off.

(C)Reduce reserve to appropriate level and to remove obsolete inventory.

(D)Includes $8 million due to the adoption of ASU 2016-13.

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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 IZZO
									Ralph Izzo
									Chairman of the Board, President and
									Chief Executive Officer

Date: February 24, 2022

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 IZZO

Chairman of the Board, President, Chief Executive Officer and

February 24, 2022

Ralph Izzo

Director (Principal Executive Officer)

/s/ DANIEL J. CREGG

Executive Vice President and Chief Financial Officer

February 24, 2022

Daniel J. Cregg

(Principal Financial Officer)

/s/ ROSE M. CHERNICK

Vice President and Controller

February 24, 2022

Rose M. Chernick

(Principal Accounting Officer)

/s/ WILLIE A. DEESE

Director

February 24, 2022

Willie A. Deese

/s/ SHIRLEY ANN JACKSON

Director

February 24, 2022

Shirley Ann Jackson

/s/ DAVID LILLEY

Director

February 24, 2022

David Lilley

/s/ BARRY H. OSTROWSKY

Director

February 24, 2022

Barry H. Ostrowsky

/s/ SCOTT G. STEPHENSON

Director

February 24, 2022

Scott G. Stephenson

/s/ LAURA A. SUGG

Director

February 24, 2022

Laura A. Sugg

/s/ JOHN P. SURMA

Director

February 24, 2022

John P. Surma

/s/ SUSAN TOMASKY

Director

February 24, 2022

Susan Tomasky

/s/ ALFRED W. ZOLLAR

Director

February 24, 2022

Alfred W. Zollar

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SIGNATURES



									PUBLIC SERVICE ELECTRIC AND GAS COMPANY

						By:			/s/ KIM C. HANEMANN
									Kim C. Hanemann
									President

Date: February 24, 2022

Signature

Title

Date

/s/ RALPH IZZO

Chairman of the Board and Chief Executive Officer and

February 24, 2022

Ralph Izzo

Director (Principal Executive Officer)

/s/ DANIEL J. CREGG

Executive Vice President and Chief Financial Officer

February 24, 2022

Daniel J. Cregg

(Principal Financial Officer)

/s/ ROSE M. CHERNICK

Vice President and Controller

February 24, 2022

Rose M. Chernick

(Principal Accounting Officer)

/s/ DAVID LILLEY

Director

February 24, 2022

David Lilley

/s/ SHIRLEY ANN JACKSON

Director

February 24, 2022

Shirley Ann Jackson

/s/ SUSAN TOMASKY

Director

February 24, 2022

Susan Tomasky

177