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Public Service Electric & Gas (PEG)

Filed: 24 Feb 22, 5:12pm
0000788784us-gaap:EquitySecuritiesMemberus-gaap:FairValueInputsLevel2Member2020-12-31
    
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
OR
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 NumberState or other jurisdiction of IncorporationI.R.S. Employer
Identification Number
001-09120  Public Service Enterprise Group IncorporatedNew Jersey22-2625848
80 Park Plaza
Newark,New Jersey07102
973430-7000
001-00973  Public Service Electric and Gas CompanyNew Jersey22-1212800
80 Park Plaza
Newark,New Jersey07102
973430-7000

Securities registered pursuant to Section 12(b) of the Act:
Title of Each ClassTrading Symbol(s)Name of Each Exchange
On Which Registered
Public Service Enterprise Group Incorporated
  Common Stock without par valuePEGNew York Stock Exchange
Public Service Electric and Gas Company
  8.00% First and Refunding Mortgage Bonds, due 2037PEG37DNew York Stock Exchange
  5.00% First and Refunding Mortgage Bonds, due 2037PEG37JNew 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 IncorporatedYesNo
Public Service Electric and Gas CompanyYesNo
    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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(Cover continued from previous page)
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 IncorporatedLarge Accelerated FilerAccelerated FilerNon-accelerated FilerSmaller reporting companyEmerging growth company
Public Service Electric and Gas CompanyLarge Accelerated FilerAccelerated FilerNon-accelerated FilerSmaller reporting companyEmerging 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
IIIPortions 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.



TABLE OF CONTENTS
 Page
FORWARD-LOOKING STATEMENTS
FILING FORMAT
WHERE TO FIND MORE INFORMATION
PART I
Item 1.Business
Operations and Strategy
Competitive Environment
Human Capital Management
Regulatory Issues
Environmental Matters
Information About Our Executive Officers (PSEG)
Item 1A.Risk Factors
Item 1B.Unresolved Staff Comments
Item 2.Properties
Item 3.Legal Proceedings
Item 4.Mine Safety Disclosures
PART II
Item 5.Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Item 6.[Reserved]
Item 7.Management’s Discussion and Analysis of Financial Condition and Results of Operations
Executive Overview of 2021 and Future Outlook
Results of Operations
Liquidity and Capital Resources
Capital Requirements
Critical Accounting Estimates
Item 7A.Quantitative and Qualitative Disclosures About Market Risk
Item 8.Financial Statements and Supplementary Data
Report of Independent Registered Public Accounting Firm (PCAOB ID No. 34)
Consolidated Financial Statements
Notes to Consolidated Financial Statements
Note 1. Organization, Basis of Presentation and Summary of Significant Accounting Policies
Note 2. Recent Accounting Standards
Note 3. Revenues
Note 4. Early Plant Retirements/Asset Dispositions and Impairments
Note 5. Variable Interest Entities (VIEs)
Note 6. Property, Plant and Equipment and Jointly-Owned Facilities
Note 7. Regulatory Assets and Liabilities
Note 8. Leases
Note 9. Long-Term Investments
Note 10. Financing Receivables
Note 11. Trust Investments
Note 12. Intangibles
Note 13. Asset Retirement Obligations (AROs)
Note 14. Pension, Other Postretirement Benefits (OPEB) and Savings Plans
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TABLE OF CONTENTS (continued)
Note 15. Commitments and Contingent Liabilities
Note 16. Debt and Credit Facilities
Note 17. Schedule of Consolidated Capital Stock
Note 18. Financial Risk Management Activities
Note 19. Fair Value Measurements
Note 20. Stock Based Compensation
Note 21. Other Income (Deductions)
Note 22. Income Taxes
Note 23. Accumulated Other Comprehensive Income (Loss), Net of Tax
Note 24. Earnings Per Share (EPS) and Dividends
Note 25. Financial Information by Business Segment
Note 26. Related-Party Transactions
Item 9.Changes In and Disagreements With Accountants on Accounting and Financial Disclosure
Item 9A.Controls and Procedures
Item 9B.Other Information
Item 9C.Disclosure Regarding Foreign Jurisdictions that Prevent Inspections
PART III
Item 10.Directors, Executive Officers and Corporate Governance
Item 11.Executive Compensation
Item 12.Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Item 13.Certain Relationships and Related Transactions, and Director Independence
Item 14.Principal Accountant Fees and Services
PART IV
Item 15.Exhibits, Financial Statement Schedules
Schedule II - Valuation and Qualifying Accounts
Signatures


ii

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

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.

iv

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.
1

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.
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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.
2

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 TypeElectricGas
Commercial56%37%
Residential35%59%
Industrial9%4%
Total100%100%
3

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
Electric2.3 Million40,163 Gigawatt hours (GWh)(0.7)%
Gas1.9 Million2,422 Million Therms0.5%
(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.
4

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).
5

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 Generation202220232024
Generation Sales95%-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:
pseg-20211231_g2.jpg
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.
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
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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:
UnitYear
Salem Unit 12036
Salem Unit 22040
Hope Creek2046
Peach Bottom Unit 22053
Peach Bottom Unit 32054
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)
NameAge as of
December 31,
2021
OfficeEffective Date
First Elected to
Present Position
Ralph Izzo64Chairman of the Board (COB), President and
Chief Executive Officer (CEO) - PSEG
April 2007 to present
COB and CEO - PSE&GApril 2007 to present
COB and CEO - PSEG PowerApril 2007 to present
COB and CEO - Energy HoldingsApril 2007 to present
COB and CEO - ServicesJanuary 2010 to present
Daniel J. Cregg58Executive Vice President (EVP) and Chief Financial Officer (CFO) - PSEGOctober 2015 to present
EVP and CFO - PSE&GOctober 2015 to present
EVP and CFO - PSEG PowerOctober 2015 to present
Ralph A. LaRossa58COB - PSEG Long Island LLCDecember 2020 to present
Chief Operating Officer (COO) - PSEGJanuary 2020 to present
President and COO - PSEG PowerOctober 2017 to present
President and COO - PSE&GOctober 2006 to October 2017
COB - PSEG Long Island LLCOctober 2013 to October 2017
Kim C. Hanemann58President and COO - PSE&GJune 2021 to present
Senior Vice President (SVP) and COO - PSE&GJanuary 2020 to June 2021
SVP - Electric Transmission and Distribution - PSE&GSeptember 2018 to January 2020
SVP - Delivery, Projects and Construction - PSE&GJuly 2014 to September 2018
Vice President (VP) - Delivery, Projects and Construction - PSE&GDecember 2010 to July 2014
Tamara L. Linde57EVP and General Counsel - PSEGJuly 2014 to present
EVP and General Counsel - PSE&GJuly 2014 to present
EVP and General Counsel - PSEG PowerJuly 2014 to present
Rose M. Chernick58VP and Controller - PSEGMarch 2019 to present
VP and Controller - PSE&GMarch 2019 to present
VP and Controller - PSEG PowerMarch 2019 to present
VP-Finance, Corporate Strategy and Planning - ServicesNovember 2017 to March 2019
VP-Finance, Holdings and Corporate Strategy and Planning - ServicesOctober 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:
NameLocationTotal
Capacity
(MW)
% OwnedOwned
Capacity
(MW)
Principal
Fuels
Used
Nuclear:
Hope CreekNJ1,185 100%1,185 Nuclear
Salem 1 & 2NJ2,285 57%1,311 Nuclear
Peach Bottom 2 & 3 (A)PA2,549 50%1,275 Nuclear
Total Nuclear6,019 3,771 
Steam:
New Haven HarborCT448 100%448 Oil/Gas
Total Steam448 448 
Combined Cycle:
KeysMD761 100%761 Gas
BergenNJ1,245 100%1,245 Gas/Oil
LindenNJ1,300 100%1,300 Gas/Oil
Sewaren 7NJ538 100%538 Gas/Oil
Bridgeport Harbor 5CT484 100%484 Gas
BethlehemNY816 100%816 Gas
KalaeloaHI208 50%104 Oil
Total Combined Cycle5,352 5,248 
Combustion Turbine:
EssexNJ81 100%81 Gas/Oil
KearnyNJ456 100%456 Gas/Oil
BurlingtonNJ168 100%168��Gas/Oil
LindenNJ336 100%336 Gas/Oil
New Haven HarborCT130 100%130 Gas/Oil
Total Combustion Turbine1,171 1,171 
Total PSEG Power Plants12,990 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.
 
201620172018201920202021
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 
pseg-20211231_g3.jpg
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 CategoryNumber 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.
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
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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,
20212020
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 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 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,
202120202019
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,
202120202019
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,
 2021202020192021 vs. 20202020 vs. 2019
 MillionsMillions%Millions%
Operating Revenues$9,722 $9,603 $10,076 $119 $(473)(5)
Energy Costs3,499 3,056 3,372 443 14 (316)(9)
Operation and Maintenance3,226 3,115 3,111 111 — 
Depreciation and Amortization1,216 1,285 1,248 (69)(5)37 
(Gains) Losses on Asset Dispositions and Impairments2,637 (123)402 2,760 N/A(525)N/A
Income from Equity Method Investments16 14 14 14 — — 
Net Gains (Losses) on Trust Investments194 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 Expense571 600 569 (29)(5)31 
Income Tax (Benefit) Expense(441)396 257 (837)N/A139 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)
2021202020192021 vs. 20202020 vs. 2019
 MillionsMillions%Millions%
Operating Revenues$7,122 $6,608 $6,625 $514 $(17)— 
Energy Costs2,688 2,469 2,738 219 (269)(10)
Operation and Maintenance1,692 1,614 1,581 78 33 
Depreciation and Amortization928 887 837 41 50 
Gain on Asset Dispositions(4)(1)— (3)N/A(1)N/A
Net Gains (Losses) on Trust Investments(1)(33)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 Expense402 388 361 14 27 
Income Tax Expense324 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)
2021202020192021 vs. 20202020 vs. 2019
 MillionsMillions%Millions%
Operating Revenues$3,147 $3,634 $4,385 $(487)(13)$(751)(17)
Energy Costs1,978 1,821 2,118 157 (297)(14)
Operation and Maintenance983 964 1,040 19 (76)(7)
Depreciation and Amortization256 368 377 (112)(30)(9)(2)
(Gains) Losses on Asset Dispositions and Impairments2,641 (122)402 2,763 N/A(524)N/A
Income from Equity Method Investments16 14 14 14 — — 
Net Gains (Losses) on Trust Investments187 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 Expense78 121 119 (43)(36)
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/FacilityAs of December 31, 2021
Total
Facility
UsageAvailable
Liquidity
 Millions
PSEG$1,500 $1,022 $478 
PSE&G600 18 582 
PSEG Power2,000 145 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 Stock202120202019
Per Share$2.04 $1.96 $1.88 
in Millions$1,031 $991 $950 
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. For additional information related to cash dividends on our common stock, see Item 8. Note 24. Earnings Per Share (EPS) and Dividends.
Credit Ratings
If the rating agencies lower or withdraw our credit ratings, such revisions may adversely affect the market price of our securities and serve to materially increase our cost of capital and limit access to capital. Credit Ratings shown are for securities that we typically issue. Outlooks are shown for 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
OutlookStable Stable
Senior NotesBaa2BBB
Commercial PaperP2 A2
PSE&G
OutlookStable Stable
Mortgage BondsA1 A
Commercial PaperP2 A2
PSEG Power
OutlookStable Stable
Issuer RatingBaa2 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.
202220232024
 Millions 
PSE&G:
Transmission$865 $800 $595 
Electric Distribution840 1,185 810 
 Gas Distribution940 1090 735 
Clean Energy275 390 390 
Total PSE&G$2,920 $3,465 $2,530 
Other140 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&G11,890 — 1,575 1,225 9,090 
Interest on Recourse Debt
PSEG444 86 118 75 165 
PSE&G6,726 407 781 694 4,844 
Operating Leases
PSE&G117 15 22 17 63 
Other152 25 36 31 60 
Energy-Related Purchase Commitments
PSEG Power2,274 697 825 494 258 
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.
Assumption202120202019
Pension
   Discount Rate2.94 %2.61 %3.30 %
   Expected Rate of Return on Plan Assets7.70 %7.70 %7.80 %
OPEB
   Discount Rate2.82 %2.46 %3.20 %
   Expected Rate of Return on Plan Assets7.69 %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.
% ChangeImpact on Benefit Obligation as of December 31, 2021Increase to Costs in 2022Increase to Costs, net of Amounts Capitalized in 2022
AssumptionMillions
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$$
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,
20212020
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$$
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 $
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.
64

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.

65

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.
66

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.
67

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.
68

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 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.

69



PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONSOLIDATED STATEMENTS OF OPERATIONS
Millions, except per share data
Years Ended December 31,
 202120202019
OPERATING REVENUES$9,722 $9,603 $10,076 
OPERATING EXPENSES
Energy Costs3,499 3,056 3,372 
Operation and Maintenance3,226 3,115 3,111 
Depreciation and Amortization1,216 1,285 1,248 
(Gains) Losses on Asset Dispositions and Impairments2,637 (123)402 
Total Operating Expenses10,578 7,333 8,133 
OPERATING INCOME (LOSS)(856)2,270 1,943 
Income from Equity Method Investments16 14 14 
Net Gains (Losses) on Trust Investments194 253 260 
Other Income (Deductions)98 115 125 
Net Non-Operating Pension and Other Postretirement Benefit (OPEB) Credits (Costs)328 249 177 
Loss on Extinguishment of Debt(298)— — 
Interest Expense(571)(600)(569)
INCOME (LOSS) BEFORE INCOME TAXES(1,089)2,301 1,950 
Income Tax Benefit (Expense)441 (396)(257)
NET INCOME (LOSS)$(648)$1,905 $1,693 
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:
BASIC504 504 504 
DILUTED504 507 507 
NET INCOME (LOSS) PER SHARE:
BASIC$(1.29)$3.78 $3.35 
DILUTED$(1.29)$3.76 $3.33 
See Notes to Consolidated Financial Statements.

70

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Millions

 
 Years Ended December 31,
 202120202019
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(14)
Pension/OPEB adjustment, net of tax (expense) benefit of $(75), $18 and $18 for the years ended 2021, 2020 and 2019, respectively190 (46)(58)
Other Comprehensive Income (Loss), net of tax154 (15)(31)
COMPREHENSIVE INCOME (LOSS)$(494)$1,890 $1,662 
See Notes to Consolidated Financial Statements.



71

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONSOLIDATED BALANCE SHEETS
Millions
December 31,
20212020
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents$818 $543 
Accounts Receivable, net of allowance of $325 in 2021 and $196 in 20201,859 1,410 
Tax Receivable63 
Unbilled Revenues, net of allowance of $12 in 2021 and $10 in 2020217 229 
Fuel296 277 
Materials and Supplies, net448 601 
Prepayments63 51 
Derivative Contracts72 60 
Regulatory Assets364 369 
Assets Held for Sale2,060 — 
Other44 27 
Total Current Assets6,250 3,630 
PROPERTY, PLANT AND EQUIPMENT43,684 48,569 
Less: Accumulated Depreciation and Amortization(9,318)(10,984)
Net Property, Plant and Equipment34,366 37,585 
NONCURRENT ASSETS
Regulatory Assets3,605 3,872 
Operating Lease Right-of-Use Assets201 262 
Long-Term Investments541 536 
Nuclear Decommissioning Trust (NDT) Fund2,637 2,501 
Long-Term Tax Receivable47 — 
Long-Term Receivable of Variable Interest Entity828 945 
Rabbi Trust Fund242 266 
Intangibles20 158 
Derivative Contracts28 
Other234 286 
Total Noncurrent Assets8,383 8,835 
TOTAL ASSETS$48,999 $50,050 
 See Notes to Consolidated Financial Statements.

72

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONSOLIDATED BALANCE SHEETS
Millions
 
December 31,
20212020
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES
Long-Term Debt Due Within One Year$700 $1,684 
Commercial Paper and Loans3,519 1,063 
Accounts Payable1,315 1,332 
Derivative Contracts17 21 
Accrued Interest121 126 
Accrued Taxes67 124 
Clean Energy Program146 143 
Obligation to Return Cash Collateral179 98 
Regulatory Liabilities388 294 
Liabilities Held for Sale144 — 
Other476 637 
Total Current Liabilities7,072 5,522 
NONCURRENT LIABILITIES
Deferred Income Taxes and Investment Tax Credits (ITC)5,759 6,502 
Regulatory Liabilities2,497 2,707 
Operating Leases191 252 
Asset Retirement Obligations1,573 1,212 
Other Postretirement Benefit (OPEB) Costs572 730 
OPEB Costs of Servco640 699 
Accrued Pension Costs318 1,128 
Accrued Pension Costs of Servco174 226 
Environmental Costs245 286 
Derivative Contracts17 
Long-Term Accrued Taxes100 88 
Other184 214 
Total Noncurrent Liabilities12,270 14,048 
COMMITMENTS AND CONTINGENT LIABILITIES (See Note 15)00
CAPITALIZATION
LONG-TERM DEBT
15,219 14,496 
STOCKHOLDERS’ EQUITY
Common Stock, no par, authorized 1,000 shares; issued, 2021 and 2020—534 shares5,045 5,031 
Treasury Stock, at cost, 2021 and 2020—30 shares(896)(861)
Retained Earnings10,639 12,318 
Accumulated Other Comprehensive Loss(350)(504)
Total Stockholders’ Equity14,438 15,984 
Total Capitalization29,657 30,480 
TOTAL LIABILITIES AND CAPITALIZATION$48,999 $50,050 
See Notes to Consolidated Financial Statements.
73

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONSOLIDATED STATEMENTS OF CASH FLOWS
Millions
Years Ended December 31,
202120202019
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 Amortization1,216 1,285 1,248 
Amortization of Nuclear Fuel187 184 178 
(Gains) Losses on Asset Dispositions and Impairments2,637 (123)402 
Loss on Extinguishment of Debt298 — — 
Emission Allowances and Renewable Energy Credit (REC) Compliance Accrual138 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 Derivatives614 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 Receivable56 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)
Other45 (70)36 
  Net Cash Provided By (Used In) Operating Activities1,736 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 Investments2,100 2,234 1,787 
Purchases of Trust Investments(2,092)(2,250)(1,814)
Proceeds from Sales of Long-Lived Assets and Lease Investments569 301 70 
Contributions to Equity Method Investments(111)— — 
Other107 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 Paper256 (352)99 
Proceeds from Short-Term Loans2,500 800 — 
Repayment of Short-Term Loans(300)(500)— 
Issuance of Long-Term Debt2,825 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 Activities799 (30)(257)
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash291 396 (23)
Cash, Cash Equivalents and Restricted Cash at Beginning of Period572 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.
74

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.AmountTotal
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.


75


PUBLIC SERVICE ELECTRIC AND GAS COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
Millions
 
Years Ended December 31,
 202120202019
OPERATING REVENUES$7,122 $6,608 $6,625 
OPERATING EXPENSES
Energy Costs2,688 2,469 2,738 
Operation and Maintenance1,692 1,614 1,581 
Depreciation and Amortization928 887 837 
Gain on Asset Dispositions(4)(1)— 
Total Operating Expenses5,304 4,969 5,156 
OPERATING INCOME1,818 1,639 1,469 
Net Gains (Losses) on Trust Investments
Other Income (Deductions)88 108 83 
Non-Operating Pension and OPEB Credits (Costs)264 205 150 
Interest Expense(402)(388)(361)
INCOME BEFORE INCOME TAXES1,770 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.

76

PUBLIC SERVICE ELECTRIC AND GAS COMPANY
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Millions

 Years Ended December 31,
 202120202019
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)
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.

77

PUBLIC SERVICE ELECTRIC AND GAS COMPANY
CONSOLIDATED BALANCE SHEETS
Millions
December 31,
20212020
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents$294 $204 
Accounts Receivable, net of allowance of $325 in 2021 and $196 in 20201,050 1,004 
Unbilled Revenues, net of allowance of $12 in 2021 and $10 in 2020217 229 
Materials and Supplies, net233 217 
Prepayments15 14 
Regulatory Assets364 369 
Other33 13 
Total Current Assets2,206 2,050 
PROPERTY, PLANT AND EQUIPMENT38,588 36,300 
Less: Accumulated Depreciation and Amortization(7,640)(7,149)
Net Property, Plant and Equipment30,948 29,151 
NONCURRENT ASSETS
Regulatory Assets3,605 3,872 
Operating Lease Right-of-Use Assets92 99 
Long-Term Investments181 222 
Rabbi Trust Fund43 51 
Other123 136 
Total Noncurrent Assets4,044 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.


78

PUBLIC SERVICE ELECTRIC AND GAS COMPANY
CONSOLIDATED BALANCE SHEETS
Millions
 
December 31,
20212020
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES
Long-Term Debt Due Within One Year$— $434 
Commercial Paper and Loans— 100 
Accounts Payable571 671 
Accounts Payable—Affiliated Companies418 479 
Accrued Interest107 101 
Clean Energy Program146 143 
Obligation to Return Cash Collateral179 98 
Regulatory Liabilities388 294 
Other376 530 
Total Current Liabilities2,185 2,850 
NONCURRENT LIABILITIES
Deferred Income Taxes and ITC4,874 4,524 
Regulatory Liabilities2,497 2,707 
Operating Leases83 88 
Asset Retirement Obligations363 314 
OPEB Costs354 485 
Accrued Pension Costs132 612 
Environmental Costs191 236 
Long-Term Accrued Taxes
Other145 154 
Total Noncurrent Liabilities8,645 9,127 
COMMITMENTS AND CONTINGENT LIABILITIES (See Note 15)00
CAPITALIZATION
LONG-TERM DEBT11,795 10,475 
STOCKHOLDER’S EQUITY
Common Stock; 150 shares authorized; issued and outstanding, 2021 and 2020—132 shares892 892 
Contributed Capital1,170 1,170 
Basis Adjustment986 986 
Retained Earnings11,524 10,078 
Accumulated Other Comprehensive Income
Total Stockholder’s Equity14,573 13,129 
   Total Capitalization26,368 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.
79

PUBLIC SERVICE ELECTRIC AND GAS COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
Millions 
Years Ended December 31,
 202120202019
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 Amortization928 887 837 
Provision for Deferred Income Taxes and ITC116 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 Liabilities10 60 62 
Employee Benefit Plan Funding and Related Payments(10)(4)(21)
Other(64)(103)(23)
Net Cash Provided By (Used In) Operating Activities1,724 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 Investments35 40 36 
Purchases of Trust Investments(29)(40)(34)
Solar Loan Investments29 13 
Other16 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 Debt1,325 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 Activities778 712 476 
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash106 183 (11)
Cash, Cash Equivalents and Restricted Cash at Beginning of Period233 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 StockContributed
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)— — — — 
Comprehensive Income1,253 
Cash Dividends Paid— — — (250)— (250)
Balance as of December 31, 2019$892 $1,095 $986 $8,928 $$11,903 
Net Income— — — 1,327  1,327 
Other Comprehensive Income (Loss), net of tax (expense) benefit of $0— — — — 
Comprehensive Income1,328 
Cumulative Effect Adjustment for CECL— — — (2)— (2)
Cash Dividends Paid— — — (175)— (175)
Contributed Capital— 75 — — — 75 
Balance as of December 31, 2020$892 $1,170 $986 $10,078 $$13,129 
Net Income— — — 1,446  1,446 
Other Comprehensive Income (Loss), net of tax (expense) benefit of $1— — — — (2)(2)
Comprehensive Income1,444 
Balance as of December 31, 2021$892 $1,170 $986 $11,524 $$14,573 
See disclosures regarding Public Service Electric and Gas Company included in the Notes to Consolidated Financial Statements.

81


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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.
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, PSEG completed the sale of this fossil generating portfolio. See Note 4. Early Plant Retirements/Asset Dispositions and Impairments for more details on the transactions.
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.
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 which holds rights to an offshore wind lease area. PSEG and Ørsted are exploring other offshore wind opportunities.
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
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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&GOther (A)Consolidated
 Millions
As of December 31, 2020
Cash and Cash Equivalents$204 $339 $543 
Restricted Cash in Other Current Assets— 
Restricted Cash in Other Noncurrent Assets22 — 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 Assets28 — 28 
Restricted Cash in Other Noncurrent Assets17 — 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.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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:
202120202019
 Avg RateAvg RateAvg Rate
Electric Transmission2.29 %2.41 %2.41 %
Electric Distribution2.56 %2.55 %2.54 %
Gas Distribution1.84 %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.
84


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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
 202120202019
 MillionsAvg RateMillionsAvg RateMillionsAvg Rate
PSE&G$93 7.37 %$112 7.86 %$81 7.22 %
Other$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.
For PSEG, cash flows for long-lived assets and asset groups are determined at the lowest level for which identifiable cash flows are largely independent of the cash flows of other assets and liabilities. The cash flows from the nuclear generation units are evaluated at the ISO regional portfolio level and, effective in August 2021 for the PJM assets, do not include PSEG’s fossil generating assets as they are classified as Held for Sale. In certain cases, generating 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. See Note 4. Early Plant Retirements/Asset Dispositions and Impairments for more information on impairment assessments performed on PSEG’s long-lived assets.
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
85


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 2. Recent Accounting Standards
New Standards Adopted in 2021
Simplifying the Accounting for Income TaxesAccounting 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 HedgingASU 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 EquityASU 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 SecuritiesASU 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.
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.
Codification ImprovementsASU 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 RefinementASU 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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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 OptionsASU 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 PaymentsASU 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.
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.
Business Combinations – Accounting for Contract Assets and Contract Liabilities from Contracts with CustomersASU 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 AssistanceASU 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.
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.
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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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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&GOther EliminationsConsolidated
Millions
Year Ended December 31, 2021
Revenues from Contracts with Customers
Electric Distribution$3,279 $— $— $3,279 
Gas Distribution1,875 — (13)1,862 
Transmission1,611 — — 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 Customers7,108 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&GOther EliminationsConsolidated
Millions
Year Ended December 31, 2020
Revenues from Contracts with Customers
Electric Distribution$3,130 $— $— $3,130 
Gas Distribution1,646 — (12)1,634 
Transmission1,485 — — 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 Customers6,599 3,734 (1,234)9,099 
Revenues Unrelated to Contracts with Customers (B)495 — 504 
Total Operating Revenues$6,608 $4,229 $(1,234)$9,603 
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PSE&GOther EliminationsConsolidated
Millions
Year Ended December 31, 2019
Revenues from Contracts with Customers
Electric Distribution$3,224 $— $— $3,224 
Gas Distribution1,870 — (15)1,855 
Transmission1,181 — — 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 Customers6,559 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 ReceivableAllowance 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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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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,
20212020
Millions
Balance at Beginning of Year$206 $68 (A)
Utility Customer and Other Accounts
     Provision195 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)-DayMW Cleared (A)
June 2021 to May 2022$1667,700 
June 2022 to May 2023$986,300 
(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
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
seven-year rate lock for BH5 through May 2026:
 
Delivery Year$ per MW-Day (A)MW Cleared (B)
June 2021 to May 2022$192950 
June 2022 to May 2023$179950 
June 2023 to May 2024$152930 
June 2024 to May 2025