0000788784pseg:PollutionControlNotesMemberpseg:PSEGPowerLLCMember2020-12-31
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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
——————————
FORM 10-K
(Mark One)
x☒ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBERDecember 31, 20172020
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
001-09120Public Service Enterprise Group IncorporatedNew Jersey22-2625848
80 Park Plaza
Newark,New Jersey07102
973430-7000
Commission
File Number
Registrants, State of Incorporation,
Address, and Telephone Number
I.R.S. Employer
Identification No.
001-09120001-00973PUBLIC SERVICE ENTERPRISE GROUP INCORPORATEDPublic Service Electric and Gas Company22-2625848New Jersey22-1212800
(A New Jersey Corporation)
80 Park Plaza
Newark,New Jersey 0710207102
973 430-7000430-7000
http://www.pseg.com
001-00973001-34232PUBLIC SERVICE ELECTRIC AND GAS COMPANYPSEG Power LLC22-1212800Delaware22-3663480
(A New Jersey Corporation)
80 Park Plaza
Newark,New Jersey 0710207102
973 430-7000430-7000
http://www.pseg.com
001-34232PSEG POWER LLC22-3663480
(A Delaware Limited Liability Company)
80 Park Plaza
Newark, New Jersey 07102
973 430-7000
http://www.pseg.com
Securities registered pursuant to Section 12(b) of the Act:
RegistrantTitle of Each Class
Trading 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
  9.25% First and Refunding Mortgage Bonds,
Public Service Electric
and Gas Company
9  1/4% Series CC, due 2021
PEG21New York Stock Exchange
8%,  8.00% First and Refunding Mortgage Bonds, due 2037PEG37DNew York Stock Exchange
5%,  5.00% First and Refunding Mortgage Bonds, due 2037PEG37JNew York Stock Exchange
PSEG Power LLC
8  5/8%
  8.625% Senior Notes, due 2031PEG31New York Stock Exchange

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Securities registered pursuant to Section 12(g) of the Act:
RegistrantTitle of Each Class
Public Service Electric and Gas CompanyMedium-Term Notes
PSEG Power LLCLimited Liability Company Membership Interest None

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Indicate by check mark whether each registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
Public Service Enterprise Group Incorporated☒
Yesx
☐
No¨
Public Service Electric and Gas Company☒
Yesx
☐
No¨
PSEG Power LLC☐
Yesx
☒
No¨
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 ¨☒ Nox
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 x☐ No¨
Indicate by check mark whether the registrants have submitted electronically and posted on their corporate Web site, if any, every Interactive Data File required to be submitted and posted 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 and post such files). ☒ Yes x☐ No¨
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ¨
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 Filer☒Accelerated Filer☐Non-accelerated Filer☐Smaller reporting company☐Emerging growth company☐
Public Service Enterprise Group Incorporated
Large accelerated filer x
Accelerated filer o
Non-accelerated filer o
Smaller reporting company o
Emerging growth company  o
Public Service Electric and Gas Company
Large accelerated filer o
Accelerated Filer
☐
Accelerated filer oFiler
☐
Non-accelerated filer xFiler
☒
Smaller reporting companyo
☐
Emerging growth companyo☐
PSEG Power LLC
Large accelerated filer o
Accelerated Filer
☐
Accelerated filer oFiler
☐
Non-accelerated filer xFiler
☒
Smaller reporting companyo
☐
Emerging growth companyo☐
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☐
PSEG Power LLC☐
 Indicate by check mark whether any of the registrants is a shell company (as defined in Rule 12b-2 of the Exchange Act).
☐ Yes ¨☒ Nox
The aggregate market value of the Common Stock of Public Service Enterprise Group Incorporated held by non-affiliates as of June 30, 20172020 was $21,673,743,255$24,648,067,675 based upon the New York Stock Exchange Composite Transaction closing price.
The number of shares outstanding of Public Service Enterprise Group Incorporated’s sole class of Common Stock as of February 16, 201819, 2021 was 504,764,707.505,093,089.
As of February 16, 2018,19, 2021, 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 privately held, beneficially and of record, by Public Service Enterprise Group Incorporated.
Public Service Electric and Gas Company and PSEG Power LLC are wholly owned subsidiaries of Public Service Enterprise Group Incorporated and each meet the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K. Each 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 20182021 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 12, 2018,15, 2021, as specified herein.



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TABLE OF CONTENTS
Page
FORWARD-LOOKING STATEMENTS
iii
FILING FORMAT AND GLOSSARY
1
WHERE TO FIND MORE INFORMATION
1
PART I
Item 1.Business
1
Regulatory Issues
1512
Environmental Matters
2218
Segment Information About Our Executive Officers (PSEG)
2521
Item 1A.Executive Officers of the Registrant (PSEG)Risk Factors
2622
Item 1A.1B.Risk FactorsUnresolved Staff Comments
2734
Item 1B.2.Unresolved Staff CommentsProperties
4034
Item 2.3.PropertiesLegal Proceedings
4135
Item 3.4.Legal ProceedingsMine Safety Disclosures
4235
Item 4.PART IIMine Safety Disclosures
42
PART II
Item 5.Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
4336
Item 6.Selected Financial Data
4537
Item 7.Management’s Discussion and Analysis of Financial Condition and Results of Operations
4637
Executive Overview of 20172020 and Future Outlook
4638
Results of Operations
5446
Liquidity and Capital Resources
6251
Capital Requirements
6655
Off-Balance Sheet Arrangements
6857
Critical Accounting Estimates
6857
Item 7A.Quantitative and Qualitative Disclosures About Market Risk
7161
Item 8.Financial Statements and Supplementary Data
7363
Report of Independent Registered Public Accounting Firm
7464
Consolidated Financial Statements
7774
Notes to Consolidated Financial Statements
Note 1. Organization, Basis of Presentation and Summary of Significant Accounting Policies
9592
Note 2. Recent Accounting Standards
9997
Note 3. Early Plant RetirementsRevenues
103100
Note 4. Early Plant Retirements/Asset Dispositions
105
Note 5. Variable Interest Entity (VIE)
104106
Note 5.6. Property, Plant and Equipment and Jointly-Owned Facilities
105107
Note 6.7. Regulatory Assets and Liabilities
106108
Note 7. Long-Term Investments8. Leases
111114
Note 8. Financing Receivables9. Long-Term Investments
113117
Note 9. Available-for-Sale Securities10. Financing Receivables
115118
Note 10.11. Trust Investments
119
Note 12. Goodwill and Other Intangibles
121125
Note 11.13. Asset Retirement Obligations (AROs)
121126
Note 12.14. Pension, Other Postretirement Benefits (OPEB) and Savings Plans
122127
Note 13.15. Commitments and Contingent Liabilities
131136
Note 14.16. Debt and Credit Facilities
138143
Note 15.17. Schedule of Consolidated Capital Stock
142148
Note 16. Financial Risk Management Activities
143

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TABLE OF CONTENTS (continued)
Note 18. Financial Risk Management Activities
148
Page
Note 17.19. Fair Value Measurements
148153
Note 18.20. Stock Based Compensation
154158
Note 19.21. Other Income and Deductions(Deductions)
157162
Note 20.22. Income Taxes
158163
Note 21.23. Accumulated Other Comprehensive Income (Loss), Net of Tax
167172
Note 22.24. Earnings Per Share (EPS) and Dividends
171177
Note 23.25. Financial Information by Business Segment
172178
Note 24.26. Related-Party Transactions
174180
Note 25. Selected Quarterly Data (Unaudited)
176
Note 26. Guarantees of Debt
177
Item 9.Changes In and Disagreements With Accountants on Accounting and Financial Disclosure
180182
Item 9A.Controls and Procedures
180182
Item 9B.Other Information
180182
PART III
Item 10.Directors, Executive Officers and Corporate Governance
185187
Item 11.Executive Compensation
186188
Item 12.Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
186188
Item 13.Certain Relationships and Related Transactions, and Director Independence
186188
Item 14.Principal Accounting Fees and Services
186188
PART IV
Item 15.Exhibits, Financial Statement Schedules
187189
Schedule II - Valuation and Qualifying Accounts
193195
Glossary of TermsSignatures
194
Signatures
196





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FORWARD-LOOKING STATEMENTS
Certain of the matters discussed in this report about our and our subsidiaries’ future performance, including, without limitation, future revenues, earnings, strategies, prospects, consequences and all other statements that are not purely historical constitute “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. Such forward-looking statements are subject to risks and uncertainties, which could cause actual results to differ materially from those anticipated. Such statements are based on management’s beliefs as well as assumptions made by and information currently available to management. When used herein, the words “anticipate,” “intend,” “estimate,” “believe,” “expect,” “plan,” “should,” “hypothetical,” “potential,” “forecast,” “project,” variations of such words and similar expressions are intended to identify forward-looking statements. Factors that may cause actual results to differ are often presented with the forward-looking statements themselves. Other factors that could cause actual results to differ materially from those contemplated in any forward-looking statements made by us herein are discussed in Item 1A. Risk Factors, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A), Item 8. Financial Statements and Supplementary Data—Note 13.15. 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 generation, transmission and distribution projects;
•lack of growth or slower growth in the number of customers or the failure of our Conservation Incentive Program to fully address a decline in customer demand;
•any equipment failures, accidents, severe weather events, acts of war or terrorism 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;
•any inability to maintain sufficient liquidity;
•the impact of cybersecurity attacks or intrusions;
•the impact of the ongoing coronavirus pandemic;
•the impact of our covenants in our debt instruments on our operations;
•adverse performance of our nuclear decommissioning and defined benefit plan trust fund investments and changes in funding requirements;
•risks associated with the timeline and ultimate outcome of our exploration of strategic alternatives relating to PSEG Power’s non-nuclear generating fleet;
•the failure to complete, or delays in completing, our proposed investment in the Ocean Wind offshore wind project, or following the completion of our initial investment in the project, the failure to realize the anticipated strategic and financial benefits of the 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;
any inability to manage•market risks impacting the operation of our energy obligations with available supply;generating stations;
increases in competition in wholesale energy and capacity markets;
•changes in technology related to energy generation, distribution and consumption and changes in customer usage patterns;
economic downturns;
•third-party credit risk relating to our sale of generation output and purchase of fuel;
adverse performance•any inability of PSEG Power to meet its commitments under forward sale obligations;
•reliance on transmission facilities to maintain adequate transmission capacity for our decommissioning and defined benefit plan trust fund investments and changes in funding requirements;power generation fleet;
•the impact of changes in state and federal legislation and regulations;regulations on our business, including PSE&G’s ability to recover costs and earn returns on authorized investments;
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•PSE&G’s proposed investment programs may not be fully approved by regulators and its capital investment may be lower than planned;
•the impact of pending rate case proceedings;if our New Jersey nuclear plants are not awarded Zero Emission Certificates (ZECs) in future periods, or the current or subsequent ZEC program period is materially adversely modified through legal proceedings;
regulatory, financial, environmental, health and safety risks associated with our ownership and operation of nuclear facilities;
•adverse changes in energy industry laws, policies and regulations, including market structures and transmission planning;
•risks associated with our ownership and operation of nuclear facilities, including 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 regulations and enforcement; and
•delays in receipt of, or an inability to receive, necessary licenses and permits;
adverse outcomes of any legal, regulatory or other proceeding, settlement, investigation or claim applicable to us and/or the energy industry;
changes in tax laws and regulations;
the impact of our holding company structure on our ability to meet our corporate funding needs, service debt and pay dividends;
lack of growth or slower growth in the number of customers or changes in customer demand;
any inability of Power to meet its commitments under forward sale obligations;
reliance on transmission facilities that we do not own or control and the impact on our ability to maintain adequate transmission capacity;
any inability to successfully develop or construct generation, transmission and distribution projects;
any equipment failures, accidents, severe weather events or other incidents that impact our ability to provide safe and reliable service to our customers;

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our inability to exercise control over the operations of generation facilities in which we do not maintain a controlling interest;
any inability to recover the carrying amount of our long-lived assets and leveraged leases;
any inability to maintain sufficient liquidity;
any inability to realize anticipated tax benefits or retain tax credits;
challenges associated with recruitment and/or retention of key executives and a qualified workforce;
the impact of our covenants in our debt instruments on our operations; and
the impact of acts of terrorism, cybersecurity attacks or intrusions.

permits.
All of the forward-looking statements made in this report are qualified by these cautionary statements and we cannot assure you that the results or developments anticipated by management will be realized or even if realized, will have the expected consequences to, or effects on, us or our business, prospects, financial condition, results of operations or cash flows. Readers are cautioned not to place undue reliance on these forward-looking statements in making any investment decision. Forward-looking statements made in this report apply only as of the date of this report. While we may elect to update forward-looking statements from time to time, we specifically disclaim any obligation to do so, even in light of new information or future events, unless otherwise required by applicable securities laws.
The forward-looking statements contained in this report are intended to qualify for the safe harbor provisions of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended.


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FILING FORMAT AND GLOSSARY
This combined Annual Report on Form 10-K is separately filed by Public Service Enterprise Group Incorporated (PSEG), Public Service Electric and Gas Company (PSE&G) and PSEG Power LLC (Power)(PSEG Power). Information relating to any individual company is filed by such company on its own behalf. PSE&G and PSEG Power are each only responsible for information about itself and its subsidiaries.
Discussions throughout the document refer to PSEG and its direct operating subsidiaries, PSE&G and PSEG Power. 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. In addition, certain key acronyms and definitions are summarized in a glossary beginning on page 194.
WHERE TO FIND MORE INFORMATION
We file annual, quarterly and current reports, proxy statements and other information with the SEC. You may read and copy any document that we file at the Public Reference Room of the SEC at 100 F Street, N.E., Washington, D.C. 20549. Information on the operation of the Public Reference Room may be obtained by calling the SEC at 1-800-SEC-0330. You may also obtain our filed documents from commercial document retrieval services, the SEC’s internet website at www.sec.gov or our website at www.pseg.com.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 tickertrading symbol PEG. You can obtain information about us at the offices of the New York Stock Exchange, Inc., 20 Broad11 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, 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 subsidiaries.
 
PSE&GPSEG Power
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.
 
Earns revenues from its regulated rate tariffs under which it provides electric transmission and electric and natural gas distribution to residential, commercial and industrial customers in its service territory. It also offers appliance services and repairs to customers throughout its service territory.
 
Also invests in regulated solar generation projects and regulated energy efficiency and related programs in New Jersey.
A Delaware limited liability company formed in 1999 as a result of the deregulation and restructuring of the electric power industry in New Jersey. It integrates the operations of its merchant nuclear and fossil generating assets with its power marketing businesses and fuel supply functions through competitive energy sales in well-developed energy markets. 
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. This is achieved primarily by selling power and transacting in natural gas and other energy-related products, on the spot market or using short-term or long-term contracts for physical and financial products.
Also earns revenues from solar generation facilities under long-term sales contracts for power and environmental products.



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Our other direct wholly owned subsidiaries are: PSEG Long Island LLC (PSEG LI), which operates the Long Island Power Authority’s (LIPA) electric transmission and distribution (T&D) system under a contractual agreement; PSEG Energy Holdings L.L.C. (Energy Holdings), which earns its revenues primarily from its portfolio of lease investments;investments and holds our investments in offshore wind ventures; and PSEG Services Corporation (Services), which provides us and our operating subsidiaries with certain management, administrative and general services at cost.
The following is a more detailed description of our business, including a discussion of our:
Business Operations and Strategy
Competitive Environment
Employee Relations
Regulatory Issues
Environmental Matters
BUSINESS OPERATIONS AND STRATEGY
PSE&G
Our regulated transmission and distributionT&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 6.2 million people, or about 70% of
New Jersey’s population resides.
.pseg-20201231_g1.gif

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Products and Services
Our utility operations primarily earn margins through the transmission and distributionT&D of electricity and the distribution of gas.
•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 areis 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.repair, in our service territory.
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In addition to our current utility products and services, we have implemented several programs to invest in regulated solar generation within New Jersey, including:
•programs to help finance the installation of solar powerpower systems throughout our electric service area, and
•programs to develop, own and operate solar power systems.
We have also implemented a set of energy efficiency and demand response programs to encourage conservation and energy efficiency by providing energy and cost savingcost-saving measures directly to businesses and families. For additional information concerning these programs and the components of our tariffs, see Regulatory Issues—State Regulation and Item 8. Financial Statements and Supplementary Data—Note 6. Regulatory Assets and Liabilities.
How PSE&G Operates
We are a transmission owner in PJM Interconnection, L.L.C. (PJM) and we provide distribution service to 2.22.3 million electric customers and 1.81.9 million gas customers in a service area that covers approximately 2,600 square miles running diagonally across New Jersey. We serve the most heavilydensely 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-typeFormula rates provide a method of rate recovery where the transmission owner annually determines its revenue requirements through a fixed formula that considers Operation and Maintenance expenditures, rate base and capital investments and applies 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 11.68%11.18% on existing and new transmission investment, while certain investments are entitled to earn an additional incentive rate. For more information, see Regulatory Issues—Federal Regulation.See Item 7. MD&A—Executive Overview of 2020 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 spendspending of $3.8$2.5 billion for transmission in 2018-20202021-2023 as disclosed in Item 7. MD&A—Capital Requirements.    
Distribution
PSE&G distributes gaselectricity and electricitynatural gas to end users in our respective franchised service territories. Our approved rates, established inIn October 2018, the BPU issued an Order approving the settlement of our most recent gas and electricdistribution base rate proceeding completed in mid-2010, providewith new rates effective November 1, 2018. The Order provides for a ROE of 10.3% on distribution rate base. In January 2018, we filedbase of $9.5 billion, a 9.60% ROE for our distribution base rate case requesting an adjustment in electricbusiness and gas base delivery rates that, if approved by the BPU, would increase overall revenues by approximately one percent. PSE&G anticipates that new base rates will take effect in the fourth quartera 54% equity component of 2018.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, withmechanisms. For a discussion of proposed and approved ROEs ranging from 9.75% to 10.3%.programs, seeItem 7. MD&A—Executive Overview of 2020 and Future Outlook. Our load requirements are split among residential, commercial and industrial (C&I) customers, as described in the following table for 2017:2020:

% of 2020 Sales
Customer TypeElectricGas
Commercial56%36%
Residential35%60%
Industrial9%4%
Total100%100%
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 % of 2017 Sales 
 Customer Type Electric Gas 
 Commercial 58% 37% 
 Residential 32% 59% 
 Industrial 10% 4% 
 Total 100% 100% 
       
While ourOur customer base has modestly increased since 2013,2016, with electric load has declined and gas load has increasedloads changing as illustrated below:
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 Electric and Gas Distribution Statistics 
       
  December 31, 2017   
  
Number of
Customers
 
Electric Sales and Gas
Firm Sales (A)
 Historical Annual Load Growth 2013-2017 
 Electric2.2
Million 40,740
Gigawatt hours (GWh) (0.4)% 
 Gas1.8
Million 2,397
Million Therms 2.8% 
          
Electric and Gas Distribution Statistics
December 31, 2020
 Number of
Customers		Electric Sales and Firm Gas
Sales (A)		Historical Annual Load Growth 2016-2020
Electric2.3 Million39,666 Gigawatt hours (GWh)(1.0)%
Gas1.9 Million2,370 Million Therms(1.2)%
(A)
(A)Excludes sales from Gas rate classes that do not impact margin, specifically Contract, Non-Firm Transportation, Cogeneration Interruptible and Interruptible Services.
The decline in electric sales isfrom Gas rate classes that do not impact margin, specifically Contract, Non-Firm Transportation, Cogeneration Interruptible and Interruptible Services.
Electric sales declined due to the resulteconomic impact of changes in customerthe ongoing coronavirus pandemic (COVID-19) on commercial usage, patterns, includinggreater conservation, and more energy efficient appliances. Gas firmappliances and increases in solar net metering installations, partially offset by an increase in residential sales increaseddue to customers staying at home during the pandemic and customer growth. Firm gas sales decreased as a result of warmer weather in 2020 and lower commercial customer usage due to the pandemic, partially offset by an increase in residential sales due to the pandemic, customer growth and customer response to continued low gas prices. Only firm gas firm sales impact margin.
PSE&G, as part of its BPU-approved Energy Strong Program, completed the replacement and modernization of 240 miles of low-pressure cast iron gas mains in or near flood areas. PSE&G continues to execute the Energy Strong Program to upgrade all of its electric substations that were damaged by water in recent storms; make investments that will create redundancy in the electric distribution system, reducing outages when damage occurs; and deploy technologies to better monitor system operations, enabling PSE&G to restore customers more quickly in the event of an electric outage, and with respect to PSE&G’s gas system, upgrade five natural gas metering stations and a liquefied natural gas station recently affected by severe weather or located in flood zones.
PSE&G continues modernizing its gas distribution system as part of our Gas System Modernization Program (GSMP) which was approved by the BPU in late 2015. The GSMP, through which we expect to invest $905 million over three years, will replace approximately 510 miles of cast iron and unprotected steel gas mains and about 38,000 unprotected steel service lines to homes and businesses, including the uprating of the mains to higher pressure. The mains and service lines will be replaced with stronger, more durable plastic piping, reducing the potential for leaks and release of methane gas. The new elevated pressure systems also enable the installation of excess flow valves that automatically shut off gas flow if a service line is damaged, and better support the use of high-efficiency appliances.
In July 2017, we filed a petition with the BPU for a GSMP II program, an extension of our GSMP through which PSE&G has proposed investing $2.7 billion over five years beginning in 2019 to continue to modernize our gas system. For additional information, see Regulatory Issues.
Solar Generation
In order to support New Jersey’s Energy Master Plan and the state’s renewable energy goals, weWe have undertaken two major solar initiatives at PSE&G, the Solar Loan Program and the Solar 4 All and Solar 4 All Extension® 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) centralizedgrid-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 and capacity 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 loanSolar Loan program, the proceeds of which are used to offset program costs.

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Supply
Although commodity revenues make up almost 38%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 own 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, which represents about 80%79% of PSE&G’s load requirements, provides default supply service for smaller industrial and commercialC&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 (CIEP))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. Results of these auctions determine which energy suppliers are authorized to supply BGS to New Jersey’s electric distribution companies (EDCs). 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. Financial Statements and Supplementary Data—Note 13.15. 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 an effective date of 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. See Item 8. Financial Statements and Supplementary Data—Note 6. Regulatory Assets and Liabilities for information on recent self-implementing 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. Commercial and industrialC&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.
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Markets and Market Pricing
Historically, there has been significant volatility in commodity prices. Such volatilityfluctuations 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. For additional information, including the impact of natural gas commodity prices on electricity prices such as BGS, see Item 7. MD&A—Executive Overview of 2017 and Future Outlook.
PSEG Power
Through PSEG Power, we seekhave sought to produce low-cost electricity by efficiently operating our nuclear, coal, gas, oil-fired and renewable generation assets while balancing generation output, fuel requirements and supply obligations through energy portfolio management. Our commitments for load, such as BGS in New Jersey and other bilateral supply contracts, are backed by the generation we own and may be combined with the use of physical commodity purchases and financial instruments from the market to optimize the economic efficiency of serving the load. 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 July 2020, we announced that we are exploring strategic alternatives for PSEG Power’s non-nuclear generating fleet with the intention of accelerating the transformation of our business into a primarily regulated electric and gas utility, with a contracted generation business. See Item 8. Note 4. Early Plant Retirements/Asset Dispositions for further discussion.
Products and Services
As a merchant generator and power marketer, our profitrevenue is derived from selling a range of products and services under contract to an array of customers, including utilities, other 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 (kWh) or dollars per megawatt hour (MWh).

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•Capacity—distinct from energy, capacity is a market commitment that a given generation unit will be available to an Independent System Operator (ISO) for dispatch to produce energy when it is needed to meet system demand. Capacity is typically priced in dollars per MW for a given sale period (e.g. day or month).
•Ancillary Services—related activities supplied by generation unit owners to the wholesale market that are required by the ISO to ensure the safe and reliable operation of the bulk power system. Owners of generation units may bid units into the ancillary services market in return for compensatory payments. Costs to pay generators for ancillary services are recovered through charges collected from market participants.
•Congestion and Renewable Energy Credits—Congestion credits (or Financial Transmission Rights) are financial instruments that entitle the holder to a stream of revenues (or charges) based on the hourly congestion price differences across a transmission path. Renewable Energy Credits (RECs) are obtained through PSEG Power’s owned renewable generation or purchased in the open market. Electric suppliers of load are required to deliver a certain amount or percentage of their delivered power from renewable resources as mandated by applicable regulatory requirements.
PSEG Power also sells wholesale natural gas, primarily through a full-requirements BGSS contract with PSE&G to meet the gas supply requirements of PSE&G’s customers. In 2014, the BPU approved an extension of the long-term BGSS contract to March 31, 2019, and then year-to-year thereafter the contract remains in effect unless terminated by either party with a two yeartwo-year notice.
Approximately 45%48% of PSE&G’s peak daily gas requirements is provided from PSEG Power’s firm gas transportation capacity, which is available every day of the year.capacity. PSEG Power satisfies the remainder of PSE&G’s requirements from storage contracts, contract peaking supply, liquefied natural gas seasonal purchases, contract peaking supply 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.
In addition to its nuclear and fossil generation fleet,PSEG Power also owns and operates 414467 MW direct current (dc) of PV solar generation facilities. 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 in the Mid-Atlantic and Northeast regions which comprises the vast majority of PSEG Power’s operations and financial performance.
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How PSEG Power’s Generation Operates
Nearly all of our generation capacity consists of nuclear and fossil generation (10,562 MW) that 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. For additional information see Item 2. Properties.
The map below shows the locations of our Northeast and Mid-Atlantic nuclear and fossil generation facilities, including projects currently under construction:•Capacity


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Generation Capacity
Our nuclear and fossil installed capacity utilizes a diverse mix of fuels. As of December 31, 2017,2020, our fuel mix was comprised of 47%57% gas, 35%34% nuclear, 11%4% coal, and 5% oil and 2% pumped storage. This fuel diversity helps to mitigate risks associated with fuel price volatility and market demand cycles.oil. Our total generating output in 20172020 was approximately 51,10052,900 GWh. ThePSEG Power has announced the early retirement of its 383 MW coal unit in Bridgeport, Connecticut in 2021. Including this planned retirement in 2021, PSEG Power will have retired or exited through sales over 2,400 MW of coal-fired generation mix by fuel type in recent years has reflected the relatively more favorable price of natural gas compared to coal, making it more economical to run certain of our gas units in place of our coal units. The following table indicates the proportionate share of generating output by fuel type insince 2017.
Generation by Fuel Type (A)Actual 2017
Nuclear:
New Jersey facilities41%
Pennsylvania facilities21%
Fossil:
Coal:
Pennsylvania facilities11%
Connecticut facilities—%(B)
Natural Gas and Oil:
New Jersey facilities17%
New York facilities10%
Connecticut facilities—%(B)
Total100%
(A)Excludes pumped storage, solar facilities and fossil generation in Hawaii which account for less than 2.5 percent of total generation.
(B) Less than one percent.
We are also executing the following growth projects which are included in the 2018-2020 planned capital spend of $520 million for Fossil Growth Opportunities disclosed in Item 7. MD&A—Capital Requirements.
Major Growth Projects
As of December 31, 2017
ProjectLocationExpected In-Service Date
Keys Energy Center gas-fired combined cycle generating station (755 MW)Maryland2018
Sewaren 7 dual-fueled combined cycle generating station (540 MW)New Jersey2018
Bridgeport Harbor 5 gas-fired combined cycle generating station (485 MW)Connecticut2019
Bethlehem Energy Center (BEC) combined cycle uprate (56 MW)New York2019(A)
Bergen dual-fueled combined cycle uprate (32 MW)

New Jersey2020
(A)Two-thirds of the project is complete and operational.
•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. In 2017, our base load capacity factors were as follows:

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Unit
2017
Capacity
Factor
Nuclear
Salem Unit 189.0%
Salem Unit 284.9%
Hope Creek100.0%
Peach Bottom Unit 299.2%
Peach Bottom Unit 391.4%
Coal
Keystone79.4%
Conemaugh75.7%
•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 and, in some cases, coal 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 and in some cases may utilize higher-priced fuels. 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, whereinenabling some gas-fired generation is now able to displace some coal-fired generation.generation by other fuel types. This change, combined with the addition of new, more efficient generation capacity, has altered the historical dispatch order of certain plants in the markets where we operate.
During periods when one or more parts of the transmission grid are operating at full capability, thereby resulting in a constraint on the transmission system, it may not be possible to dispatch units in merit order without violating transmission reliability standards. Under such circumstances, the ISO may dispatch higher-cost generation out of merit order within the congested area, and power suppliers will be paid an increased Locational Marginal Price (LMP) in congested areas, reflecting the bid prices of those higher-cost generation units.
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 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 operating profitsgross 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. This can be seen in the following graphs which present historical annual spot prices and forward calendar prices as averaged over each year at two liquid trading hubs.






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pseg-20201231_g2.jpgpseg-20201231_g3.jpg

Historical data impliesWe expect that the price of natural gas will continue to have a strong influence on the price of electricity in the primary markets in which we operate.
The prices reflected in the preceding graphs above do not necessarily illustrate our contract prices, but they are representative of market prices at relatively liquid hubs, with nearer-term forward pricing generally resulting from more liquid markets than pricing for later years. As shown above, Market wholesaleprices 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. These variations can be considerable. Concurrent with the development of regional shale gas, we have been increasing our purchases from the Marcellus/Utica shale gas regions and in 2017 they accounted for approximately 86% of the gas we procured. While these prices provide some perspective on past and future prices, the forwarddo not necessarily reflect our contract prices. Forward prices are volatile and there can be no assurance that suchcurrent 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),
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•conversion of uranium concentrates to uranium hexafluoride,
•enrichment of uranium hexafluoride, and
•fabrication of nuclear fuel assemblies.
Our nuclear fuel contracts cover approximately 100% of our estimated uranium, enrichment and fabrication requirements through 2020 and a significant portion through 2022.

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Coal Supply—Our Keystone, Conemaugh and Bridgeport stations operate on coal. Coal is delivered to our units through a combination of rail, truck, barge and ocean shipments.
In order to control emissions levels, our Bridgeport 3 unit uses a specific type of coal obtained from Indonesia. We have coal inventory at the Bridgeport Station as well as off-site storage to meet the plant’s projected requirements.
•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. These supplies are transported to New Jersey by four interstate pipelines with which we have contracted. In addition, we have firm gas transportation contracted for this winter season to serve a portion of the gas requirements for our BEC stationBethlehem Energy Center (BEC) in New York.
York and hold year-round firm gas transportation to serve the majority of the requirements of Keys Energy Center in Maryland.
We have 1.3approximately 2.3 billion cubic feet-per-day of firm transportation capacity and 0.9 billion cubic feet-per-day of 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.
Power has contracted for approximately 125 million cubic feet-per-day of delivery capability on the PennEast Pipeline from eastern Pennsylvania to New Jersey with a targeted in-service date in 2019. This additional delivery capability will be used to supplement the BGSS contract.
•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 own 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 20172020 and Future Outlook and Item 8. Financial Statements and Supplementary Data—Note 13.15. Commitments and Contingent Liabilities.
Markets and Market Pricing
The vast majority of PSEG Power’s generation assets are located in three centralized, competitive electricity markets operated by ISO organizations all of which are subject to the regulatory oversight of FERC:
•PJM Regional Transmission Organization—PJM conducts the largest centrally dispatched energy market in North America. It serves over 65 million people, nearly 20% of the total United States population, and has a record peak demand of 165,492 MW. 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. The majority of our generating stations operate in PJM.
•New York—The New York ISO (NYISO) is the market coordinator for New York State and is responsible for managing the New York Power Pool and for administering its energy marketplace. This service area has a population of about 19 million and a record peak demand of 33,956 MW. Our BEC generating station operates in New York.
•New England—The ISO-New England (ISO-NE) is the market coordinator for the New England Power Pool and for administering its energy marketplace which covers Maine, New Hampshire, Vermont, Massachusetts, Connecticut and Rhode Island. This service area has a population of about 15 million and a record peak demand of 28,130 MW. Our Bridgeport and New Haven stations operate in Connecticut.
The price of electricity varies by location in each of these markets. Depending uponon our production and our obligations, these price differentials may increase or decrease our profitability.
Commodity prices, such as electricity, gas, coal, oil and environmental products, as well as the availability of our diverse fleet of generation units to operate, also 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.
Over the past fewseveral years, lower wholesale natural gas prices have resulted in lower electric energy prices. One of the reasons for the lower natural gas prices is greater supply from more recently-developed sources, such as shale gas, much of which is produced in adjacent states (e.g. Pennsylvania). This trend has reduced margin on forward sales as we re-contract our expected generation output.

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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. Currently, there is sufficient capacity in the markets in which we operate. However, in certain areasSee Item 7. MD&A—Executive Overview of these markets there are transmission system transfer limitations which raise concerns about reliability2020 and create a more acute need for capacity.Future Outlook—Wholesale Power Market Design.
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In PJM and ISO-NE, where we operate most of our generation, the market design for capacity payments provides for a structured, forward-looking, transparent capacity pricing mechanism. This is through the Reliability Pricing Model (RPM) in PJM and the Forward Capacity Market (FCM) in ISO-NE. These mechanisms provide greater transparencyFor additional information regarding FERC actions related to the value of capacity and provide a pricing signal to prospective investors in new generating facilities so as to encourage expansion of capacity to meet future market demands.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. Keystone and Conemaugh receive lower capacity prices than the majority of our PJM generating units since there are fewer constraints in that region and our generating units in New Jersey usually receive higher pricing.
Our PJM generating units are located in several zones andzones. The average capacity prices that PSEG Power expects to realize the following average capacity pricesreceive from the base and incremental auctions which have been completed:
Delivery YearMW-day
June 2017 to May 2018$177
June 2018 to May 2019$215
June 2019 to May 2020$116
June 2020 to May 2021$174
completed are disclosed in Item 8. Note 3. Revenues. The price that must be paid by an entity serving load in the various zones is also set through these auctions. These prices can be higher or lower than the prices noteddisclosed in the table aboveItem 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 2021 2022 through the RPM pricing mechanismand New England capacity through May 20222026 forBridgeport Harbor Unit 5 and May 2024 for New Haven through the RPM and FCM pricing mechanisms, respectively.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 monthsix-month auction period.
On a prospective basis, many factors may affect the capacity pricing, including but not limited to:
load and demand,
availability of generating capacity (including retirements, additions, derates and forced outage rates),
capacity imports from external regions,
transmission capability between zones,
available amounts of demand response resources,
pricing mechanisms, including potentially increasing the number of zones to create more pricing sensitivity to changes in supply and demand, as well as other potential changes that PJM and the other ISOs may propose over time, and
legislative and/or regulatory actions that permit subsidized local electric power generation.
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.

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Among the ways in which we hedgehave hedged our output are: (1) sales at PJM West or other nodes corresponding to our generation portfolio and (2) BGS and similarphysical load sales as full-requirements contracts. Sales atin PJM Westgenerally 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. The BGS-RSCP contract, a full-requirements contract that includes energy and capacity, ancillary and other services, is awarded for three-year periods through an auction process managed by the BPU. The volume of BGS contracts and the mix of electric utilities that our generation operations serve will vary from year to year. Pricing for the BGS contracts, including a capacity component, for recent and future periods by purchasing utility is as follows:
           
 Load Zone ($/MWh) 2015-2018 2016-2019 2017-2020 2018-2021 
 PSE&G $99.54 $96.38 $90.78 $91.77 
 Jersey Central Power & Light Company (JCP&L) $80.42 $74.85 $69.08 $73.11 
 Atlantic City Electric Company $86.06 $82.14 $75.49 $81.23 
 Rockland Electric Company $90.66 $85.02 $80.50 $85.94 
           
Although we enter into these hedges in an effort 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. In addition, our use of full requirements contracts as a hedging strategy is expected to decline if the strategic alternatives for PSEG Power’s non-nuclear assets result in a disposition of these assets. Actual output will vary based upon total market demand, the relative cost position of our units compared to other units in the market and the operational flexibility of our units. Hedge volume can also vary, depending on the type of hedge into which we have entered. The BGS auction, for example, results in a contract that provides for the supplier to serve a percentage of the default load of a New Jersey EDC, that is, the load that remains after some customers have chosen to be served directly either by third-party suppliers or through municipal aggregation. The amount of power supplied through the BGS auction varies based on the level of the EDC’s default load, which is affected by the number of customers who are served by third-party suppliers, as well as by other factors such as weather and the economy.
In recent years, as market prices declined from previous levels, there was an incentive for more of the smaller commercial and industrial electric customers to switch to third-party suppliers. In a falling price environment, this has a negative impact on our margins, as the anticipated BGS pricing is replaced by lower spot market pricing. As average BGS rates have declined to a level that more closely resembles current market prices, customers may see less of an incentive to switch to third-party suppliers. We are unable to determine the degree to which this switching, or “migration,” will continue, but the impact on our results could be material should market prices fall or rise significantly.
Power is developing a retail energy business to sell energy directly to commercial and industrial customers. We believe a retail energy platform complements our existing wholesale generation-to-load marketing business that is intended to hedge our generation assets. Power began these marketing activities in 2017 and has been granted retail energy supplier licenses in New Jersey, Pennsylvania and Maryland.
As of February 8, 2018, we had contracted for the following percentages of our anticipated base load generation output for the next three years with modest amounts beyond 2020.
         
 Base Load Generation 2018 2019 2020 
 Generation Sales 100% 95%-100% 50%-55% 
         
In a changing market environment, this hedging strategy may cause our realized prices to differ materially from current market prices. In a rising price environment, this strategy normally results in lower margins than would have been the case had no hedging activity been conducted. Alternatively, in a falling price environment, this hedging strategy will tend to create margins higher than those implied by the then-current market.
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 20202021 and a significant portion through 2022. In March 2017, Westinghouse Electric Company (WEC) announced that it had filed for Chapter 11 bankruptcy in New York. WEC provides nuclear fuel fabrication services for Salem Units 1 and 2. In January 2018, Brookfield Business Partners LP announced its intention to acquire WEC. The acquisition is expected to close in 2018 if it receives the required approvals from the regulators and bankruptcy courts. No assurances can be given that the acquisition will be approved. In the event that WEC is unable to continue to provide fabrication services, we can provide no assurance that Power would be able to find alternative providers of such services in a timely manner or on acceptable terms. A failure by WEC to perform its obligations during the pendency of, or following its emergence from, bankruptcy could have a material adverse impact on our business, the financial results of specific plants and on our results of operations.

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We also have various long-term fuel purchase commitments for coal to support our Keystone and Conemaugh stations. These purchase obligations are consistent with our strategy in general to enter into contracts for our fuel supply in comparable volumes to our sales contracts.
We take a more opportunistic approach in hedging both the fuel for and the anticipated output of our natural gas-fired generation. The generation from thesemore efficient load following units iscan be estimated with a moderate degree of certainty. The peaking units are less predictable, as a significant portion of these units will only dispatch when aggregate market demand has exceeded the supply provided by lower-cost units. The natural gas-fired units are hedged based on their expected generation; however, at much lower thresholds than base load generation. Additionally, the recent developmentavailability of low-cost gas supplies in the Marcellus region presents opportunities during certain portions of the year to procure gas for our generating units at attractive prices.
More than half70% of PSEG Power’s expected gross margin in 20182021 relates to our hedging strategy, our expected revenues from the capacity market mechanisms described above, ZEC revenues and certain 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:
Other
Base Load Generation202120222023
Generation Sales100%65%-70%30%-35%
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Energy Holdings
Lease Investments
Energy Holdings primarily owns and manages a portfolio of domestic lease investments. The majority of Energy Holdings’ $565 million of domestic lease investments are primarily energy-related leveraged leases. As of December 31, 2017, the counterparties for 59% of our total leveraged lease investments were rated below investment grade by Standard & Poor’s (S&P). See Item 8. Financial Statements and Supplementary Data—Note 8.10. Financing Receivables for additional information.
Energy Holdings’ leveraged leasing portfolio is designedOffshore Wind
In December 2020, PSEG entered into a definitive agreement with Ørsted North America to provideacquire a fixed rate of return. Leveraged lease investments involve three parties: an owner/lessor, a creditor and a lessee. In a typical leveraged lease financing, the lessor purchases an asset25% equity interest in Ørsted’s Ocean Wind project. Ocean Wind was selected to be leased.New Jersey’s first offshore wind farm as part of the state’s intention to add 7,500 MW of offshore wind generating capacity by 2035. The purchase priceOcean Wind project could provide first power in late 2024. Completion of the acquisition is typically financed 80% with debt providedanticipated to occur in the first half of 2021, subject to approval by the creditorBPU and the balance comes from equity funds provided by the lessor. The creditor provides long-term financingother customary closing conditions. Additionally, PSEG and Ørsted each owns 50% of Garden State Offshore Energy LLC which holds rights to the transaction secured by the property subject to the lease. Such long-term financing is non-recourse to the lessoran offshore wind lease area. PSEG and with respect to our lease investments, is not presented on our Consolidated Balance Sheets.Ørsted are exploring other offshore wind opportunities.
The lessor acquires economic and tax ownership of the asset and then leases it to the lessee for a period of time no greater than 80% of its remaining useful life. As the owner, the lessor is entitled to depreciate the asset under applicable federal and state tax guidelines. The lessor receives income from lease payments made by the lessee during the term of the lease and from tax benefits associated with interest and depreciation deductions with respect to the leased property. Our ability to realize these tax benefits is dependent on operating gains generated by our other operating subsidiaries and allocated pursuant to the consolidated tax sharing agreement between us and our operating subsidiaries.
Lease rental payments are unconditional obligations of the lessee and are set at levels at least sufficient to service the non-recourse lease debt. The lessor is also entitled to any residual value associated with the leased asset at the end of the lease term. An evaluation of the after-tax cash flows to the lessor determines the return on the investment. Under accounting principles generally accepted in the United States (GAAP), the leveraged lease investment is recorded net of non-recourse debt and income is recognized as a constant return on the net unrecovered investment.
For additional information on leases, including the credit, tax and accounting risks, see Item 1A. Risk Factors, Item 7A. Quantitative and Qualitative Disclosures About Market Risk—Credit Risk, and Item 8. Financial Statements and Supplementary Data—Note 8. Financing Receivables.LIPA Operations Services Agreement
In accordance with a twelve year Amended and Restated 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. As required by the OSA, PSEG LI also provides certain administrative support functions to LIPA. PSEG LI uses its brand in the Long Island T&D service area. Pursuant toUnder 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. In addition,Also, there is thean opportunity for the parties to extend the contract for an additional eight years subject to the achievement by PSEG LI of certain performance levels during the initial term of the OSA. Also,Further, since January 2015, PSEG Power provides fuel procurement and power management services to LIPA under separate agreements. See Item 7. MD&A—Executive Overview of 2020 and Future Outlook. 

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COMPETITIVE ENVIRONMENT
PSE&G
Our T&D business is minimally impacted when customers choose alternate electric or gas suppliers since we earn our return by providing transmission and distributionT&D service, not by supplying the commodity. Increased reliance by customers on net-metered generation, including solar, and changes in customer behaviors can result in decreased reliance on our system and impact our revenues and investment opportunities. The demand for electric energy and gas by customers is affected by customer conservation, economic conditions, weather and other factors not within our control. Construction of new local generation and changing customer usage patterns also have the potential to reduce the need for the construction of new transmission to transport remote generation and alleviate system constraints. However, our Conservation Incentive Program (CIP), which was recently approved by the BPU as part of our Clean Energy Future-Energy Efficiency (CEF-EE) program, 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 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. The CIP is effective in June 2021 for electric revenues and October 2021 for gas revenues.
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” (ROFR) 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 implementing rules within the regions are still in fluxcontinue 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. For additional information, see the discussion in Regulatory Issues—Federal Regulation—Transmission Regulation, below.
Construction of new local generation and changing customer usage patterns also have the potential to reduce the need for the construction of new transmission to transport remote generation and alleviate system constraints.
PSEG Power
Various market participants compete with us and one another in transacting in the wholesale energy markets, entering into bilateral contracts and selling to individual and aggregated retail customers. 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
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•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. Although it is not clear if thisSuch capacity will be built or, if so, what the economic impact will be, such additions wouldcould impact market prices and our competitiveness.
Our business is also under competitive pressure due to demand sidedemand-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. Changes implementedFor 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 PJMcapacity market and New Englandwhether subsidized resources may be adversely affecting capacity markets and other proposed market changes discussed more fullyprices. For information regarding recent actions by FERC relating to capacity market design, see the discussion in Regulatory Issues���Issues—Federal Regulation provide the opportunity for additional compensation in both the energy and capacity markets.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.

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While it is our expectation that continued efforts may be undertaken by the federal and state governments to preserve the existing base of fossil and nuclear generating plants, we still believe that pressures from renewable resources will continue to increase. For example, many parts
HUMAN CAPITAL MANAGEMENT
At PSEG, we know that our people are our most valuable resource. Our Human Capital Management objective is to ensure we have the best talent and culture to sustain our business.
PSEG continuously strives for a culture of the country, including the mid-western region served by the Midwest Independent System Operator (MISO), the PJM regioninclusion that supports its employees, customers and the California ISO, have either implemented or proposed implementing changesmany diverse communities we serve. Fundamental to their respective regional transmission planning processesour culture are our Core Commitments–safety; integrity; continuous improvement; customer service; and diversity, equity and inclusion. Through these Core Commitments, we seek to attract, develop and retain a diverse, high-performing workforce that may enable the constructiondrives organizational performance and fosters a culture of large amounts of “public policy” transmission to move renewable generation to load centers. For additional information, see the discussion in Regulatory Issues—Federal Regulation.
EMPLOYEE RELATIONScollaboration, learning and comfort speaking up where new ideas are welcome and employees feel valued and enhance each other’s performance.
As of December 31, 2017, we had 12,9452020, PSEG employed 12,788 full-time employees, within our subsidiaries, including 7,999of which 61% are covered underby collective bargaining agreementsagreements. Women represent 18% of the PSEG workforce and 26% of our employees are people of color. Of our full-time external hires in 2020, 41% were women or racially/ethnically diverse.
Diversity, Equity and Inclusion
In 2020, PSEG added “equity” to our Diversity & Inclusion commitment. We performed a comprehensive review of our policies and practices, resulting in updates of our programs to better support equity. We expanded our paid parental leave program and have begun to revise our hiring practices to allow greater access to job opportunities. We conduct semi-annual equity reviews of compensation for non-represented employees and incorporate multiple levels of calibration of performance ratings. In 2020, we also launched a disability inclusion campaign to better understand our employee population self-identifying as having a disability.
We have a strong and active Employee Business Resource Group (EBRG) network of over 25 employee groups connected in 12 focus areas Enterprise-wide that is closely aligned to PSEG’s business objectives. These EBRGs encompass groups including, but not limited to, Black Professionals, Asian & Pacific Islanders, Hispanic/LatinX, LGBTQ+, People with eightDisabilities, New Hires, Women, Working Parents & Caregivers, and Veterans.
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Talent Management and Engagement
PSEG is committed to attracting, developing and retaining a robust talent pipeline, from our front lines to our leadership levels. In 2020, we created a women-in-skilled-trades initiative, and are piloting a partnership model with historically Black colleges and universities. Our People Strong training programs provide development at different career levels from our newly hired college graduates and front line supervisors to executive leadership pipeline. In 2020, we trained our top 200+ leaders in developing inclusive leadership skills. We also doubled participation in women’s leadership development programs and pioneered a new program for Black professionals in support of increasing representation in leadership ranks. To support safe and reliable operations, we invest in technical and operational training for our craft and field workers.
We solicit continuous feedback so that we improve our culture in a way that is responsive to the voices of our employees. We conduct surveys, focus groups and listening sessions throughout the year, in addition to our annual Your Voice Matters employee experience survey. In 2020, our overall employee engagement score was 86%, and 88% of employees reported feeling proud to work at PSEG.
Total Rewards
In addition to our competitive pay, incentives and benefits programs, our Total Rewards offerings take into account the safety, health and overall well-being of our employees. We offer an array of programs designed to support physical, emotional, and financial wellness. Our benefits programs are designed to support our employees through everyday challenges, critical life events, and new and changing life experiences. Our programs include access to live 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 7,786 employees represented by unions expiring from 2019 through 2022. We believe we maintain satisfactory relationshipsin our workforce. Our strong relationship with our employees.unions allowed for swift and effective implementation of COVID-19 protocols. In 2020, we extended several of our labor contracts through dates in 2023, providing labor stability during the pendency of key business initiatives.
As we accelerate our business to a primarily regulated utility and contracted energy business with zero-carbon nuclear assets, 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.
           
 Employees as of December 31, 2017 
 
  
 PSE&G Power PSEG LI Services 
 Non-Union 1,959
 1,118
 881
 988
 
 Union 5,209
 1,293
 1,486
 11
 
 Total Employees 7,168
 2,411
 2,367
 999
 
           
COVID-19 Response for Our Employees
In light of the national emergency and global pandemic due to COVID-19, PSEG activated its business continuity plan and enacted new work practices, workplace safety protocols, and expanded employee benefits and support to ensure the safety, health and wellness of our employees. Throughout the pandemic, we have maintained our workforce levels and provided frequent education to frontline managers and the workforce. We implemented remote work practices for all employees whose job could be performed remotely.
A pandemic response hotline was put in place to guide employees through questions about their COVID-19-related health and safety, to provide identification and notification of close contact exposure, and to offer clinical assessments to determine quarantine needs and appropriate return-to-work procedures.
We provided COVID-19 related paid time off for employees to take care of themselves and their family members, get vaccinated and to navigate school and daycare closures. We expanded our bereavement leave practice and enhanced childcare resources to support working parents. We have designed our Responsible Reentry approach and playbook for future business practices.
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 3. Legal Proceedings and Item 8. Financial Statements and Supplementary Data—Note 13.15. 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
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 Federal Power Act (FPA)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
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that is regulated by FERC (such as a transmission line or a generating station); collect costs from customers associated with a new transmission facility; charge a rate for wholesale sales under a contract or tariff; or engage in certain mergers and internal corporate reorganizations.
FERC also regulates generating facilities known as qualifying facilities (QFs). QFs are cogeneration facilities that produce electricity and another form of useful thermal energy, or small power production facilities where the primary energy source is renewable, biomass, waste or geothermal resources. QFs must meet certain criteria established by FERC. We own various QFs through PSEG Power. QFs are subject to some, but not all, of the same FERC requirements as public utilities.
FERC also regulates Regional Transmission Operators (RTOs)/ISOs, such as PJM, and their energy and capacity markets.
For us, the major effects of FERC regulation fall into five general categories:
Regulation of Wholesale Sales—Generation/Market Issues/Market Power
Energy Clearing Prices
Capacity Market Issues
Transmission Regulation
Compliance

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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 (MBR(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 market-based rate (MBR)MBR sales. For a requesting company to receive MBR Authority, FERC must first make a determinationdetermine that the requesting company lacks market power in the relevant markets and/or that market power in the relevant markets is sufficiently mitigated. The followingCertain PSEG companies are public utilities and currently have MBR Authority: PSE&G, PSEG Energy Resources & Trade (ER&T), PSEG Fossil, PSEG Nuclear, PSEG Power Connecticut, PSEG New Haven, PSEG Energy Solutions, PSEG Keys Energy Center LLC, Pavant Solar II LLC, San Isabel Solar LLC and Bison Solar LLC. FERC requires that holders of MBR Authority file an update every three years demonstrating that they continue to lack market power and/or that their market power has been sufficiently mitigated and report in the interim to FERC any material change in facts from those FERC relied on in granting MBR Authority.
In November 2017, FERC issued an order accepting the triennial filing made by the PSEG companies seeking authority to sell energy, capacity and ancillary services at market-based rates.
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 within a delivery zone receive a clearing price based on the bid of the marginal unit (i.e. the last unit that must be dispatched to serve the needs of load) which can vary by location. In addition, recent rule changes in the energy markets administered by PJM and ISO-NE (see Capacity Market Issues below) impose rigorous performance obligations and nonperformancenon-performance penalties on resources during times of system stress. These FERC rules provide an opportunity for bonus payments or require the payment of penalties depending on whether a unit is available during a performance hour.
In April 2019, FERC has also ordered certain favorableissued an order directing PJM and NYISO to change their rules governing pricing for fast-start resources. In its Order, FERC found that current fast-start pricing practices are unjust and unreasonable because they do not allow prices to reflect the marginal cost of serving load. FERC required PJM and NYISO to make various changes to energy market price formation rules improving shortagetheir respective tariffs to allow the start-up costs of fast-start resources to be reflected in prices, among other things. In August 2019, PJM stated that new tariff provisions would apply fast-start pricing to all eligible fast-start resources. However, in January 2020, FERC decided to hold the proceeding in abeyance in order to allow PJM and its stakeholders to address FERC’s concern that PJM’s pricing and enhancing bidding flexibility for units.dispatch are misaligned. In December 2020, FERC issued an order accepting aspects of PJM’s proposed reforms, but also directed PJM to submit an additional filing that includes an implementation date. The new rules will not be implemented until FERC issues an order approving PJM’s final compliance filing. We will continue to advocateparticipate in this contextproceeding.
In May 2020, FERC issued an order approving PJM’s proposal to modify the curves used for additional changes in market rules that would provide more transparency regarding operator actions affecting energy market prices and would promotepricing reserves with FERC. The reforms include a consolidation of synchronized reserve products, improved use of existing capability for locational reserve needs, better alignment between generation dispatch decisionsof reserve products in day-ahead and energy market price outcomes. We cannot predict what actions FERC might ultimately take, but such an examination could leadreal-time markets, a downward-sloping operating reserve demand curve, and increased penalty factors to future rule changes.
In June 2017, PJM issued an energy price formation proposalensure use of all supply prior to address a flaw in the energy market in which energy prices during off-peak periods often do not reflect the production costs of generators during these periods even though they are serving load. PJM’s proposal would allow large, inflexible units to set price. If placed into effect, this proposal will improve price formation by ensuring that the marginal costs of units serving loadreserve shortage. These reforms will be better reflectedimplemented in clearing prices. We cannot predictMay 2022.
In January 2020, New Jersey rejoined the outcomeRegional 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 this matter.a carbon pricing mechanism that may mitigate the environmental and financial distortions that could occur when emissions “leak” from non-participating states to the RGGI states. The process is expected to continue through 2021and if it leads to a market solution, could have a material impact on the value of PSEG Power’s generating fleet.
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
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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.
During 2015,In December 2019, FERC issued an order establishing new rules for PJM’s capacity market. In this new order, FERC extended the PJM implementedMinimum 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.
PSEG Power’s New Jersey nuclear plants that receive ZEC payments will be subject to the new MOPR. Resources that are subject to the MOPR continue to have the ability to justify a new “Capacity Performance” (CP) mechanism that created a more robust capacity product with enhanced incentives for performance during emergency conditions and significant penalties for non-performance, which was implemented fullybid below the MOPR floor price under the unit-specific exemption. The MOPR floor prices are not expected to prevent either our nuclear or gas-fired units from clearing in the next RPM auction. In May 20172020, FERC issued an order modifying PJM’s methodology for pricing energy reserves. It also directed PJM to use forward-looking energy and ancillary service revenues, which can affect how the MOPR offer floors are calculated. In addition, if one or more electric distribution zones in New Jersey (or another state) were to become fixed resource requirement (FRR) service areas, procurements needed for that area could provide an alternate means for nuclear units whose ability to clear in RPM auction forauctions was affected by the 2020-2021 Delivery Year. The CP mechanism is intendedMOPR to enhance the participation of intermittent and demand response resources (seasonal resources). Specifically, FERC approved PJM’s modifications to the aggregation rules to improve the ability of seasonal resources to participate. However, two complaints remain pending that ask FERC to investigate the rules governing the participation of seasonal resources and extend the participation of the base resources for future auctions. provide capacity within PJM.
We cannot predict whether additional changes will be made to the outcomeMOPR, or whether changes will occur in the PJM market that would impact our ability to clear any of these matters.units in future RPM auctions.
States that have clean energy programs designed to achieve public policy goals that support such resources as solar, offshore wind and nuclear are not prevented from pursuing those programs by the expanded MOPR and could choose to utilize the existing FRR approach authorized under the PJM issuedtariff. The FRR provides a series of white papers in response to public policies that seek to recognize value associated with generation plants beyond their cost effectiveness and reliability attributes. The three proposals are intended to spur stakeholder discussion and include both potential capacity and energy market reforms. The first energy market reform (see Energy Clearing Prices and

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Price Formation Initiatives) would allow inflexible generating units to set prices resulting in reduced uplift payments and improved price signals while the second energy market reform contemplates a voluntary carbon pricing program where states that elect to participate in the program would agree to put a price on carbon emissions. The capacity market proposal contemplates a two-stagemeans other than PJM’s capacity auction which,for an entity obligated to supply customers to satisfy its capacity obligation. Accordingly, subsidized units that cannot clear in an RPM capacity auction because of the expanded MOPR could still count as capacity resources to a load serving entity using the FRR approach. In a March 2020 order, the BPU initiated an investigation to examine whether New Jersey can achieve its long-term clean energy and environmental objectives under the current form, would improve prices for unsubsidized resources, but would still continue to provide capacity payments for subsidized resources. The two-stage capacity market auction is now pending beforeresource adequacy procurement paradigm and potential alternatives. One of the PJM stakeholders for consideration.areas of inquiry concerns the potential creation of FRR service areas within New Jersey.
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 CPCapacity 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. One aspect of the current market design that we do not support due to the capacity market suppression associated with this mechanism is the exemption from the MOPR in the capacity market afforded for up to 200 MW annually (600 MW cumulatively) of renewable resources. Recently, ISO-NE submitted proposed changes to the FCM referred to as the Competitive Auctions and Sponsored Policy Resources (CASPR) proposal to accommodate clean and renewable energy policy resources. The CASPR design creates a second auction that commences immediately following the Forward Capacity Auction and provides the opportunity for certain renewable, clean and alternative energy resources to acquire supply obligations when they cannot clear economically in the Forward Capacity Auction. The CASPR design also proposed to phase out the 200 MW exemption from the minimum offer price rule (MOPR). We cannot predict the outcome of this proceeding.
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 unless sufficient market protections are adopted.
One capacity market matter pending before FERC involves rules to govern payments and bidding requirements for generators proposing to exit the market but required to remain in service for reliability reasons. In March 2015, FERC issued an order which held that units receiving special reliability payments could properly take those payments into account in formulating capacity market bids. We believe that this ruling could impact efficient price formation in the capacity market and could artificially suppress capacity market outcomes. In April 2015, a trade association, Independent Power Producers of New York, Inc. (IPPNY) of which Power is a member, filed for rehearing by FERC of this ruling. This rehearing is still pending. Also, in connection with this same proceeding, FERC required NYISO to submit a report addressing whether buyer-side mitigation measures are needed for new entry occurring in the “Rest of State” (ROS) region and for uneconomic retention and repowering anywhere in the state. NYISO filed a report with FERC in December 2015 contending that these measures are not needed. The IPPNY has opposed NYISO’s contentions. The matter remains pending before FERC. In addition, in May 2015, the New York Public Service Commission and other New York agencies filed a complaint at FERC requesting certain exemptions from the NYISO rules that prevent capacity suppliers from submitting bids that are not market competitive. In October 2015, FERC granted in part, certain of the requested exemptions for renewable resources and for resources being used by the owner for self-supply. The IPPNY has challenged NYISO’s proposed implementation of the newly required exemptions. This challenge is still pending.
Price Formation Initiatives
Power has been actively involved both through stakeholder processes and through filings at FERC in seeking improvements to the rules for setting prices for energy in the day-ahead and real-time markets administered by PJM and other system operators. FERC recently issued an order instituting an investigation into the pricing of fast-start resources by three grid operators, PJM, NYISO and Southwest Power Pool. Fast-start resources typically are committed in real-time, very close to the interval when needed and can respond quickly to unforeseen system needs. However, without fast-start pricing, some fast-start resources are ineligible to set prices due to inflexible operating limits. As a result, prices may not reflect the marginal cost of serving load. PJM submitted a response to FERC’s order that supported reforms to fast-start pricing with minor modifications. PJM also contended that all fast-start resource scheduled by PJM should be eligible to set locational marginal prices. We cannot predict the impact that these changes may have on our business.
Notice of Proposed Rulemaking (NOPR) on Baseload Generation
In September 2017, the Secretary of the U.S. Department of Energy (DOE) issued a NOPR to allow a full recovery of costs for certain eligible units physically located within the FERC-approved organized markets. In January 2018, FERC issued an order terminating the proceeding and initiating a new proceeding to explore resilience issues with the RTOs and ISOs. In the new proceeding, FERC is requiring each RTO and ISO to respond to a series of questions that appear to be intended to gain an

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understanding of the steps each RTO and ISO is taking to ensure the resilience of their respective grids. We expect to participate in this proceeding, but we are unable to predict the outcome.
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. Our allowed ROE is 11.68% for both existing
Transmission Rate Proceedings and new transmission investments and we have received incentive rates, affording a higher ROE, for certain large scale transmission investments.
In October 2017, the 2018 Annual Formula Rate Update was filed with FERC and requested approximately $212 million in increased annual transmission revenues effective January 1, 2018, subjectReturn on Equity—From time to true-up. In January 2018, PSE&G filed with FERC a revised 2018 Annual Transmission Formula Rate Update reducing the 2018 transmission annual revenue requirement to reflect the federal corporate income tax rate reduction from 35% to 21%, effective January 1, 2018, as provided in new comprehensive tax legislation enacted in December 2017 (Tax Act). This change in the federal corporate income tax rate reduces the annual revenue requirement by $148 million. Each year, transmission revenuestime, various matters are adjusted to reflect items such as updating estimates used in the filing with actual data. For additional information about our transmission formula rate, see Item 8. Financial Statements and Supplementary Data—Note 6. Regulatory Assets and Liabilities.
Transmission Policy Developments—FERC concluded in Order 1000 that the incumbent transmission owner should not always have a ROFR to construct and own transmission projects in its service territory. The current PJM rules retain carve-outs for projects that will continue to default to 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 and whose construction would interfere with incumbents’ use of their rights-of-way.
In a February 2016 order, FERC reversed a previous order and accepted a filing by the PJM transmission owners seeking authority to assign costs for Regional Transmission Expansion Plan projects (subject to PJM Board approval requirements) solely addressing localized needs to customers within the local transmission owner’s zone. FERC’s action in this order provides an exemption from the Order 1000 open window procedures for projects constructed by transmission owners to meet local transmission planning criteria. FERC’s orders have been challenged at the D.C. Circuit and PSE&G has intervened in support of FERC.
There are several matters pending before FERC that concern the allocationrelating to, among other things, transmission planning, reliability standards and transmission rates and returns, including incentives. Depending on their outcome, any of costs associated with transmission projects being constructed by PSE&G contending that insufficient levelsthese matters could materially impact our results of costs are being allocated to customers in the PSE&G transmission zone. Projects involved include the Artificial Island project, the Bergen-Linden project in New Jerseyoperations and a smaller project in Sewaren, New Jersey. financial condition.
In April 2016, FERC issued orders denying the complaints and leaving the current cost allocation in effect as to the Artificial Island and Bergen-Linden projects. Due to an intervening FERC order concerning the allocation of costs for projects constructed to meet local reliability requirements, FERC directed that all of the Sewaren costs be allocated to customers in the PSE&G transmission zone. It is anticipated that additional proceedings are likely to occur.
In February 2016,November 2019, FERC issued an order granting PSE&G’s request that it be permittedestablishing a new ROE policy for reviewing existing transmission ROEs. The new methodology uses the discounted cash flow (DCF) model and capital asset pricing model (CAPM) to seek recovery of 100% of its portion of the project’s costs to address identified high voltage issues at Artificial Island in New Jerseydetermine if the projectan existing base ROE is canceled for reasons beyond PSE&G’s control. In April 2016,unjust and unreasonable and, if so, what replacement ROE is appropriate. PSE&G accepted construction responsibility for the three components of the project that PJM assigned to it, based on having reached agreement with PJM regarding an estimate for the project base cost of $273 million, plus risk and contingency for a total project cost of up to $340 million. In March 2017, PJM staff made its final recommendation tojoined the PJM Board with respect to the project. In April 2017, the PJM Board approved a portionTransmission Owners in requesting rehearing of the project to PSE&G of the construction of necessary upgrade work at a cost of approximately $130 million. In October 2017, FERC accepted PJM’s filingFERC’s order on the grounds that PJM correctly applied its Tariff. However,the new methodology is flawed. In May 2020, FERC deferredpartially granted rehearing of the November 2019 order and again revised the ROE methodology by reinstating the risk premium model with the CAPM and DCF models. FERC’s order indicated that it would not be bound by this revised methodology when considering the just and reasonableness of a ruling on whetherutility’s ROE in future proceedings. We continue to analyze the cost allocation methodology applied topotential impact of these methodologies.
ROE complaints have been pending before FERC regarding Midcontinent Independent System Operator (MISO) transmission owners, the Artificial Island project is appropriate. FERC will decide this issueISO New England Inc. transmission owners and utilities in a separate proceedingother jurisdictions. In addition, over the past few years, several companies have negotiated settlements that is currently pending. have resulted in reduced ROEs.
We are unable to predictengaged in settlement discussions with the outcome.BPU Staff and the New Jersey Division of Rate Counsel (New Jersey Rate
In June 2015, a
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Counsel) about the level of PSE&G’s base transmission developer filed a complaint against PJM claiming that PJM wrongfully refused to provide data and a transparent process for evaluating transmission network upgrade requests that the transmission developer had submitted to PJM. Although not named as a respondent, the complaint identifies PSE&G as one of the companies claimed to have been involved. In January 2018, a FERC administrative law judge issued an order generally finding that PJM and transmission owners, including PSE&G, did not engage in wrongful conduct. In addition, the developer’s assertion of an entitlement to monetary damages was expressly denied. However, in a determination disputed by PSE&G, the order found that the PJM process lacked transparency. The judge’s order will now be briefed by all parties for additional determinations by FERC.We are unable toROE; however, we cannot predict the outcome of these proceedings.settlement discussions. An adverse change to PSE&G’s base transmission ROE or ROE incentives could be material.

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Another proceeding is a matter remanded from a federal appellate court concerning the appropriate cost allocation for certain 500 kV projects in PJM that either have been built or are in the process of being built. A proposed settlement was filed with FERC in June 2016. The settlement, if adopted by FERC, would result in increased annual cost allocations to customers in the PSE&G transmission zone. Under this settlement, Power, as a BGS supplier could become obligated to pay amounts previously paid by other PJM transmission customers. However, we do not believe that the anticipated level of any such potential payments would have a material effect on Power’s financial statements. We believe that there is a mechanism in place under the BGS contract for the pass-through of increases in transmission charges.
In February 2018, FERC issued an order finding that the transmission planning procedures used by the PJM transmission owners, a group that includes PSE&G, for supplemental projects do not adhere to the coordination and transparency principles of FERC’s Order No. 890. FERC determined that certain terms and conditions in the PJM governing documents are unjust and unreasonable. FERC directed PJM and the PJM transmission owners to submit certain revisions to the manner in which the stakeholder process for supplemental projects is conducted. PSE&G will be participating in the PJM transmission owners’ compliance filing.
Transmission Rate Proceedings—Numerous complaints have been filed at FERC in recent years seeking to reduce the base ROE of transmission owners across the country. Many of those complaints were resolved through agreement and settlement resulted in ROE reductions while others remain pending in the FERC adjudication process or are being litigated in the courts. Recent court decisions, as well as anticipated changes in the makeup at FERC, create some uncertainty as to the timing and outcome of these complaints. The results of these settlement and proceedings could set precedents for other transmission owners with formula rates in place, including PSE&G.
Con Edison Wheeling Agreement—Effective May 1, 2017, a wheeling arrangement which enabled Con Edison to move 1,000 MW of power from southeastern New York across the PSE&G system for delivery into New York City expired. Amounts that would have been recovered from Con Edison had this arrangement continued are now being recovered from other customers.  PSE&G believes the current planning assumptions used by PJM are consistent with sound transmission planning principles. However, PSE&G disagrees with the absence of a mechanism to assign PJM transmission upgrade costs to Con Edison that reflect Con Edison’s reliance on the PJM transmission grid. PSE&G and the BPU jointly filed a rehearing application at FERC seeking reversal of a determination not to create such a mechanism in connection with a PJM/NYISO joint operating agreement. In addition, in December 2017, the BPU filed a complaint at FERC against Con Edison and others petitioning FERC to create such a cost allocation mechanism that would assign PJM costs to New York.
Compliance
FERC—For information about the preliminary non-public investigation initiated by the FERC Staff regarding errors in the calculation of certain components of Power’s cost-based bids for its New Jersey fossil generating units in the PJM energy market and the quantity of energy that Power offered into the energy market for its fossil peaking units compared to the amounts for which Power was compensated in the capacity market for those units, see Item 8. Financial Statements and Supplementary Data—Note 13. Commitments and Contingent Liabilities.
Reliability Standards—Congress has required FERC to put in place, through the North American Electric Reliability CouncilCorporation (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, FERC directed the NERC to draft a physical security standard intended to further protect assets deemed “critical” to reliability of the grid. In November 2014,July 2015, FERC issued an order approving the NERC’s proposed physical security standard. Under the standard, utilities will beare 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 couldcan decide or be required to build additional redundancy into their systems. This standard will supplementsupplements the Critical Infrastructure Protection standards that are already in place and that establish physical and cybersecurity protections for critical systems. We are taking steps to meet these obligations. FERC directed the 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 bulk electric systemgrid operations. When adopted, complianceFERC 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 new standards would be expected to impose additional obligations and costs.standards.
Commodity Futures Trading Commission (CFTC)CFTC
In accordance with the Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act), the SEC and the CFTC are in the process of implementing a new regulatory framework for swaps and security-based swaps. The legislation was enacted 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. To implement the Dodd-Frank Act, the CFTC has engaged in a comprehensive rulemaking process and has issued a number of proposed and final rules addressing many of the key issues. We are currently subject to recordkeeping and data reporting requirements applicable to commercial end users. The CFTC has also re-proposed

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rules establishing position limits for trading in certain commodities, such as natural gas, and we will begin complying with these rules once they become final.
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 security and protection of 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 also necessary.
The NRC has the ultimate authority to determine whether any nuclear generating unit may operate. 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 22033
Peach Bottom Unit 32034
The NRC conducts ongoing reviews of nuclear industry operating experience and may issue or revise regulatory requirements as a result of these ongoing reviews.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 ourthe Salem, Hope Creek and Peach Bottom facilities, but such costs could be material.
In March 2020, Exelon, co-owner of the Peach Bottom nuclear facilities in Pennsylvania, received approval from the NRC for a second 20-year license renewal for Peach Bottom Units 2 and 3. 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
Since our operations are primarily located within New Jersey, ourOur principal state regulator is the BPU, which oversees electric and natural gas distribution companies in New Jersey. We are also subject to various other states’ regulations due to our operations in those states.
Our New Jersey utility operations are subject to comprehensive regulation by the BPU including, among other matters, regulation of retail electric and gas distribution rates and service, the issuance and sale of certain types of securities and compliance matters. PSE&G’s participation in solar demand response and energy efficiency programs is also regulated by the BPU, as the terms
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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.
We must file electric and gas rate cases with the BPU in order to change our utility base distribution rates. In January 2018, PSE&G filed a distribution base rate case as required by the BPU as a condition of approval of PSE&G’s Energy Strong Program. The filing requests $9.6 billion in rate base as of December 31, 2018, a 10.3% return on equity and a capitalization structure with a 54% equity component. The filing also requests an approximate one percent increase in revenues and seeks to recover investments made to strengthen electric and gas distribution systems. In its filing, PSE&G requested that these rates take into account a reduction in the revenue requirement as a result of the federal corporate income tax rate reduction from 35% to 21% provided in the Tax Act including a one-time credit for estimated excess income taxes collected between January 1, 2018 and the time new rates go into effect, and the flow-back to customers of certain additional tax benefits. PSE&G anticipates the new base rates will go into effect in the fourth quarter of 2018.
Separately, in January 2018, the BPU issued an order commencing a proceeding to ensure that the rate revenue resulting from expenses relating to taxes reflected in rates but no longer owed as the result of the Tax Act shall be passed onto the ratepayers. The BPU directed New Jersey utilities (including PSE&G) to make filings by March 2, 2018 setting forth interim rates to be effective April 1, 2018 reflecting the new federal corporate tax rate, and to subsequently file proposed final rates, effective July 1, 2018, incorporating all other effects of the Tax Act. This proceeding is currently pending.
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 case 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 cash flow. For additional information
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) of reducing electric and gas consumption by at least 2% and 0.75%, respectively. 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 specific filings, see Item 8. Financial Statements and Supplementary Data—Note 6. Regulatory Assets and Liabilities.
Infrastructure Investment Program (IIP)—The BPU has enacted IIPbusiness or results of operations from the EMP or any laws, rules or regulations that allow utilities to construct, install or remediate utility plant and facilities related to reliability, resiliency and/or safety to support the provision of safe and adequate

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service. Under these regulations, utilities can seek authority to make specified infrastructure investments in programs extending for up to five years with accelerated cost recovery mechanisms. The BPU characterized the IIP regulationspromulgated as a regulatory initiative intendedresult thereof, particularly as they may relate to create a financial incentive for utilities to acceleratePSEG 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 agencies may take in light of the levelEnvironmental Protection Agency’s (EPA) Affordable Clean Energy (ACE) rule and other federal initiatives associated with climate change or the impact of investment needed to promote the timely rehabilitation and replacementany such actions on our business or results of certain non-revenue producing infrastructure that enhances reliability, resiliency, and/or safety. operations.
Gas System Modernization Program II (GSMP II)—In July 2017, we filed a petitionConcurrently with the release of the EMP, New Jersey Governor Murphy signed an executive order directing the New Jersey Department of Environmental Protection (NJDEP) to establish a greenhouse gas (GHG) monitoring and reporting program, adopt new regulations to reduce CO2 emissions and reform environmental land use regulations to incorporate climate change considerations into permitting decisions. We cannot predict the impact of this executive order.
BGSS Process—In September 2019, the BPU formally opened a stakeholder proceeding to explore gas capacity procurement and related issues with respect to service to all New Jersey natural gas customers, whether served through BGSS or a third- party supplier. In addition, the BPU directed that the proceeding review whether, and to what extent, third-party suppliers are providing savings to New Jersey customers on their natural gas supply. The Board Staff has conducted a public hearing and interested parties, including PSE&G, have submitted oral and written comments while also answering the Staff’s specific questions concerning, among other things, capacity procurement (e.g., timing, price, sufficiency); the sufficiency of pipeline capacity within New Jersey; the cost impacts if gas distribution companies were made responsible for a GSMP II program, an extensionsecuring incremental capacity for their transportation customers; and economic benefits to residential customers. The proceeding remains open.
BGS Process—InJuly 2020, the State’s EDCs filed their annual proposal for the conduct of GSMPthe February 2021 BGS auction covering electric supply for energy years 2022 through 2024. In prior years, the BPU and BGS suppliers 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, 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 will continue to modernize our gas system, through which PSE&G has proposed investing $2.7 billion over five years beginning in 2019. Under this proposed program, we plan to replace up to 1,250 miles of gas mains and associated service lines, with cost recovery atcollect transmission costs from its BGS customers as a 9.75% rate of return on equity through an accelerated recovery mechanism. This matter is pending. We believe the petition is consistent with the IIP regulations thatsupply cost. In November 2020, the BPU approved both proposals. As a result, (a) the 2021 BGS auction product excluded the obligation for the BGS suppliers to provide transmission and (b) BGS suppliers now have 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 December 2017, as described above.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.
New Jersey Solar Initiatives—Pursuant to the Clean Energy Efficiency 2017Act, the BPU was required to undertake several initiatives in connection with New Jersey’s solar energy market.
The BPU established a “Community Solar Energy Pilot Program, (EE 2017)—” permitting customers to participate in solar energy projects remotely located from their properties, and allowing for bill credits related to that participation effective in February 2019. The BPU is currently engaged in a stakeholder process with the State’s EDCs and others regarding 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 developing a cost recovery mechanism for the EDCs.
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The Clean Energy Act required the BPU to close the 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, including PSE&G, are required to purchase, using the services of a TREC administrator, TRECs from solar projects at rates set by the BPU. PSE&G filed for rate recovery of these costs in April 2020. In August 2017,2020, the BPU approved PSE&G’s petitionrate recovery filing. The BPU is continuing to work with the state’s EDCs to establish the mechanisms for EE 2017implementing the transition incentive program.
Cybersecurity
In an effort to extend three existing energy efficiency subprograms (multi-family, direct installreduce the likelihood and hospital efficiency)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, 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 our Company and 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.
•Cybersecurity Excellence Oversight Board (CEOB)—provides the Chief Operating Officer with periodic cybersecurity assessments of PSEG. The CEOB is comprised of employee and non-employee members who have expertise in technology security, compliance and controls, or in management practices.
•Cybersecurity Awareness—Identifying and assessing cyber risks through partnerships with public and private entities and industry groups, and disseminating electronic notices to, and conducting presentations for, company personnel.
•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—Deploying 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 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 twocybersecurity 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.
FERC further directed NERC to develop a new residential energy efficiency offerings. The two new offerings include deployment of smart thermostats and a pilot programreliability standard to provide residential customerssecurity controls for supply chain management associated with energy usage information enabling themthe procurement of industrial control system hardware, software, and services related to reduce consumption. EE 2017, asbulk electric system operations. FERC approved allows PSE&Gthe supply chain risk management standard in October 2018, with an implementation date of October 1, 2020. We have documented procedures and implemented new processes to extend the subprogram offerings and establish the residential energy efficiency sub-programs under its existing energy efficiency clause recovery process. comply with these standards.
State—The EE 2017 allows for $69 million of additional investment and $16 million of additional administrative and information technology costs. The EE 2017 was added as the eleventh component of the Green Program Recovery Charges (GPRC) rate effective September 1, 2017.
BPU Cybersecurity Requirements for Regulated Entities—In March 2016, the BPU issued an order for the regulated electric, natural gas and water/wastewater utilities to further reduce the potential for cyber threats to the reliability and resiliency of utility service and to protect customers’ information. The Order requires these regulated utilities, including PSE&G, to, among other conditions,things, implement a cybersecurity program that defines and implements organizationorganizational accountabilities and responsibilities for cyber risk management activities, and establishes policies, plans, processes and procedures for identifying and mitigating cyber risk to critical systems. New Jersey utilities, including PSE&G, were requiredAdditional requirements of this order include, but are not limited to: (i) annually inventorying critical utility systems; (ii) annually assessing risks to be compliant with these requirements by October 1, 2017. We have submitted the required certificationcritical utility systems; (iii) implementing controls to mitigate cyber risks to critical utility systems; (iv) monitoring log files of compliancecritical utility systems; (v) reporting cyber incidents to the BPU.
In an effort to reduce the likelihoodBPU; and severity of cyber incidents, we have(vi) establishing a comprehensive cybersecurity program designed to protect and preserve the confidentiality, integrity and availability of our company and our customers’ information and our systems. In addition, we are subject to maintaining key cybersecurity controls to meet mandatory cybersecurity regulatory requirements. Our cybersecurity program is built on technical, procedural, and people-focused measures to detect, protect against, respond to, and recover from cyber threats to our systems and information including company, employee and customer data. Features of our program include: identifying critical information and systems; conducting cyber risk assessments of our and third party systems; maintaining awareness of cyber threats and vulnerabilities through partnerships with public and private entities, as well as industry groups; maintaining and testing our cybersecurity incident response plansplan and systems; training personnel on cybersecurity issues;conducting biennial exercises to test the plan. In addition, New York’s Stop Hacks and raising cybersecurity awareness throughout our company with electronic notices and seminars. We cannot assure that our cybersecurity program will beImprove Electronic Data Security (SHIELD) Act, which became effective in preventingMarch 2020, requires businesses that own or mitigating cybersecurity incidents. For a discussion of the risks associated with cybersecurity threats, see Item 1A. Risk Factors.license computerized data that includes New York State residents’ private information to implement reasonable safeguards to protect that information.
Consolidated Tax Adjustments (CTA)—New Jersey is one of only a few states that make CTA in setting rates for regulated utilities. These adjustments to rate base are madeduring the rate-setting process andare intended to allocate to utility customers a portion of the tax benefits realized from the filing of a consolidated federal tax return by the utility’s parent corporation. The BPU has been considering the appropriateness of the adjustment and the methodology and mechanics of the calculation for some time. In October 2014, the BPU approved a proposal by its Staff that limits the tax benefit period to be considered in the calculation to five years, sets the distribution rate base adjustment at 25% of any such tax benefit and eliminates from the process any tax benefits tied to transmission earnings. In accordance with this action, this CTA policy will be applied only with respect to future distribution rate base cases, including our distribution base rate case filed in January 2018. In November 2014, the New Jersey Division of Rate Counsel appealed the BPU’s decision and in September 2017, the New Jersey Superior Court, Appellate Division granted that appeal on procedural grounds. Upon remand, in January 2018, and updated in February 2018, the BPU issued a draft proposed rule that is pending review by the Office of Administrative Law. The draft proposal includes a 60-day comment period. We do not expect the application of a CTA to have a material impact on PSE&G’s current earnings or its distribution base rate case filing.
Federal Tax Legislation —As a result of the enactment of the Tax Act, various state regulatory authorities, including the BPU, have taken action to ensure that excess federal income taxes previously collected in rates are returned to ratepayers. We have made filings to adjust the revenue requirement in certain of our rate matters as a result of the change in federal income tax rate. 
We continue to assess whether any further action needs to be taken by the company at this time.

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Additional matters are discussed in Item 8. Financial Statements and Supplementary Data—Note 6. Regulatory Assets and Liabilities.
ENVIRONMENTAL MATTERS

We are subject to federal, state and local laws and regulations with regard to environmental matters including, but not limited to:
•air pollution control,
•climate change,
•water pollution control,
•hazardous substance liability, and
•fuel and waste disposal.
We expect there will be changes to existing environmental laws and regulations, particularly in light of the change in administration following the 2020 U.S. presidential election that could significantly impact the manner in which our operations are currently conducted. Such laws and regulations may also affect the timing, cost, location, design, construction and operation of new facilities. Due to evolving environmental regulations, 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 Item 3. Legal Proceedings and Item 8. Financial Statements and Supplementary Data—Note 13.15. 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 CAAClean Air Act 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 Clean Air Act, for facilities located in what the law defines as overburdened communities. With this law, New Jersey has embarked on a
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path toward a legislative goal that no community should bear “a disproportionate share of the adverse environmental and public health consequences that accompany New Jersey’s economic growth.” The law does not go into effect until the NJDEP adopts implementing regulations. The regulations are anticipated to be finalized by year-end 2021.
Hazardous Air Pollutants Regulation—In February 2012, theEnvironmental Protection Agency(EPA)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 (NESHAP) provisions of the CAA.Clean Air Act. The MATS established allowable levels for mercury as well as other hazardous air pollutants (HAPS) and went into effect in April 2015. In June 2015, the U.S. Supreme Court held that it was unreasonable for the EPA to refuse to consider the materiality of costs in determining whether to regulate hazardous air pollutants from power plants. In April 2016, the EPA released the final Supplemental Finding that considers the materiality of costs in determining whether to regulate hazardous air pollutants from power plants in response to a ruling bythe U.S. Supreme Court’s ruling.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 have filed petitions with the D.C. Circuit challenging the EPA’s Supplemental Finding. The
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 is holdingCourt. We cannot predict the case in abeyance pending further directions from the EPA. We do not expectoutcome of this Supplemental Finding to impact operation of our facilities.matter.
Climate Change
CO2 Regulation under theCAAClean Air Act—In October 2015,June 2019, the EPA published the New Source Performance Standards (NSPS) for new power plants. The NSPS establishes two emission standards for CO2issued its final ACE rule as a replacement for the following categories: (i) fossil fuel-fired utility boilers and integrated gasification combined cycle units, and (ii) natural gas combustion turbines. Simple cycle combustion turbines are exempt from the rule.
In October 2015, the EPA also published therepealed Clean Power Plan, (CPP), a greenhouse gas (GHG) emissionsGHG emission regulation under the CAA for existing power plants. The regulation establishes state-specific emission rate targets based on implementationACE 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 best system of emission reduction (BSER). The BSER consists of three components: (i) heat rate improvements at existing coal-fired power plants, (ii) increased use of existing natural gas combined cycle capacity, and (iii) operation of incremental zero-emitting generation (renewables and nuclear). States may choose these or other methodologies to achieve the necessary reductions of CO2 emissions.

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Numerous states and several industry groups filed petitions for reviewACE rule with the D.C. CourtCircuit challenging the EPA’s narrow interpretation of BSER. In January 2021, the D.C. Circuit vacated the ACE rule and remanded the rulemaking to challenge the CPP. In addition, the petitioners sought a stay of the rule. The U.S. Supreme Court stayed the rule pending further review of the case.
In March 2017, the President of the United States issued an Executive Order that instructed the EPA to reviewfor further consideration. We cannot predict the NSPS that establish emissions standards for CO2 for certain new fossil power plants and the CPP. The D.C. Circuit granted the EPA’s motion to hold the case in abeyance while the agency reviewed the rule. Upon completionoutcome of the review, the EPA Administrator signed a proposed repeal of the CPP. The EPA Administrator concluded that the CPP exceeds the EPA’s statutory authority by considering measures that are beyond the control of the owners of the affected sources (fossil fuel-fired electric generating units). The EPA is considering rulemaking to replace the CPP. PSEG cannot assess thethis matter or estimate its impact of any such rulemaking on our business and futureor results of operations at this time.operations.
Regional Greenhouse Gas Initiative (RGGI)RGGI—In response to concerns over global climate change, some states have developed initiatives to stimulate national climate legislation through CO2 emission reductions in the electric power industry. Certain northeastern states (RGGI States), including New York participate in the RGGI and Connecticut where we have generation facilities, havestate-specific rules in place to enable the RGGI regulatory mandate in each state to cap and reduce CO2 emissions. These rules make allowances available through a regional auction whereby generators may acquire allowancesGenerating plants operating in RGGI states that are each equalemit CO2 will have to one ton of CO2 emissions. Generators are required to submit an allowanceprocure credits for each ton emitted over a three-year period. Allowances are available through the auction or through secondary markets.
In September 2017, the RGGI States announced their newthat they emit. The post-2020 program for a cap on regional CO2 emissions which would requirefor 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 New Jersey Department of Environmental Protection (NJDEP),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. In January 2018,
New Jersey Governor Murphy signed anProtecting Against Climate Threats (NJ PACT)—In response to a New Jersey Executive Order, requiring the NJDEP has undertaken a regulatory reform effort that is designed to initiate the rulemaking process formodernize environmental laws, referred to as New Jersey Protecting Against Climate Threats (NJ PACT). When implemented, NJ PACT is expected to reenter RGGI.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. We cannot estimatecontinue to assess the potential impact of this action onthe NJ PACT, which could have cost implications for construction of new or upgrades to existing utility infrastructure and upgrades of our business fossil generation facilities. Such expenditures could materially affect the continued economic viability and/or results of operations at this time.cost to construct one or more such facilities.
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
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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 that directly govern our facilities in those jurisdictions.
Steam Electric Effluent Guidelines—In September 2015, the EPA issued a new Effluent Limitation Guidelines Rule (ELG Rule) for steam electric generating units. The rule establishes new best available technology economically achievable (BAT) standards for fly ash transport water, bottom ash transport water, flue gas desulfurization and flue gas mercury control wastewater, and gasification wastewater. Power’s Bridgeport Harbor station and the jointly-owned Keystone and Conemaugh stations have bottom ash transport water discharges that are regulated under the ELG Rule. Keystone and Conemaugh also have flue gas desulfurization wastewaters regulated by the ELG Rule.
Through various orders, the EPA has stayed the compliance dates in the ELG Rule and has announced plans to further revise the requirements and compliance dates of the ELG Rule. Power is unable to determine how this will ultimately impact its compliance requirements or its financial condition and results of operations.
Cooling Water Intake Structure Regulation—In May 2014, the EPA issued a final cooling water intake rule under Section 316(b) of theEPA’s Clean Water Act (CWA) thatSection 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 has structuredrequires that the rule soNPDES permits be renewed every five years and that each state Permitting Director will continue to considermanage renewal permits for existingits respective power generation facilities on a case by case basis, based on studies related to impingement mortality and entrainment and submitbasis. The NJDEP manages the results with their permit applications to be conducted by the facilities seeking renewal permits.
Several environmental organizations and certain energy industry groups have filed suitpermits under the CWA and the Endangered Species Act. The cases have been consolidated at the Second Circuit and a decision remains pending.

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We are assessing the potential impact of the rule on each of our affected facilities and are unable to predict the outcome of permitting decisions and the effect, if any, that they may have on our future capital requirements, financial condition or results of operations, although such impacts could be material. See Item 8. Financial Statements and Supplementary Data— Note 13. Commitments and Contingent Liabilities for additional information.  
In June 2016, the NJDEP issued the final New Jersey Pollutant Discharge Elimination System (NJPDES) permit for Salem. The final permit does not mandate specific service water system modifications but, consistent with Section 316(b) of the CWA, it requires additional studiesprogram. Connecticut and the selection of technology to address impingement for the service water system. In July 2016, the Delaware Riverkeeper Network (Riverkeeper) filed a request challenging the NJDEP’s issuance of the final NJPDES renewal permit for Salem. NJDEP has granted the hearing request, but it has not yet been scheduled. The Riverkeeper’s filing does not change the effective date of the permit. For additional information, see Item 8. Financial Statements and Supplementary Data—Note 13. Commitments and Contingent Liabilities.
A permit application for renewal of the current NPDES permit for the Bridgeport Harbor Station Unit 3 (BH3) is under review by the Connecticut Department of Energy and Environmental Protection (CTDEEP). To address compliance with the EPA’s CWA Section 316(b) final rule, weNew York also have proposed to continue to operate BH3 without making the capital expenditures for modification to the existing intake structure and retire the BH3 within five years of the effective date of the final permit. Based on discussions with the CTDEEP, if the proposal is accepted, a final NPDES permit could be issued with a retirement date for BH3 by summer 2021, which is four years earlier than the previously estimated useful life ending in 2025. If the permit is not issued and the conditions below are not met, we may seek to operate BH3 through the previously estimated useful life.
We have negotiated a Community Environmental Benefit Agreement (CEBA) with the City of Bridgeport, Connecticut. That CEBA provides that we would retire BH3 early if all of its conditions precedent occur, which include receipt of all final permits to build and operate a proposed new combined cycle generating facility on the same site that BH3 currently operates. Absent those conditions being met, and the permit renewal referred to above not being issued, we may seek to operate BH3 through the previously estimated useful life. See Item 8. Financial Statements and Supplementary Data—Note 3. Early Plant Retirements.
In February 2016, the proposed generating facility, Bridgeport Harbor Station Unit 5 (BH5), was awarded a capacity obligation. Construction has commenced and operations are expected to begin in mid-2019. The Connecticut Siting Council issued an order to approve siting BH5. All major environmental permits have been obtained except for the modified Title V air permit.
Bridgeport Harbor National Pollutant Discharge Elimination System (NPDES) Permit Compliance—In April 2015, we determined that monitoring and reporting practices related to certain permitted wastewater discharges at our Bridgeport Harbor station may have violated conditions of the station’s NPDES permit and applicable regulations and could subject us to fines and penalties. We have notified the CTDEEP of the issues and have taken actions to investigate and resolve the potential non-compliance. We cannot predict the impact of this matter.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 from hazardous substances, including obligations to conduct environmental remediation of discharged hazardous substances as well asand 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. See Item 3. Legal Proceedings. 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. For additional information, see Item 8. Financial Statements and Supplementary Data—Note 13. Commitments and Contingent Liabilities.
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.

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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 DOEUnited States Department of Energy (DOE) reduced the nuclear waste fee to 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 LevelLow-Level Radioactive Waste—As a by-product of their operations, nuclear generation units produce low levellow-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 levellow-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 LevelLow-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.
SEGMENT INFORMATION
Financial information with respect to our business segments is set forth in Item 8. Financial Statements and Supplementary Data—Note 23. Financial Information by Business Segment.

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INFORMATION ABOUT OUR EXECUTIVE OFFICERS OF THE REGISTRANT (PSEG)
Name
Name
Age as of

December 31,
2017

2020		Office
Effective Date

First Elected to

Present Position
Ralph Izzo6063
Chairman of the Board (COB), President and

Chief Executive Officer (PSEG)
(CEO) - PSEG		April 2007 to present
Chairman of the BoardCOB and Chief Executive Officer (PSE&G)CEO - PSE&GApril 2007 to present
Chairman of the BoardCOB and Chief Executive Officer (Power)CEO - PSEG PowerApril 2007 to present
Chairman of the BoardCOB and Chief Executive Officer (Energy Holdings)CEO - Energy HoldingsApril 2007 to present
Chairman of the BoardCOB and Chief Executive Officer (Services)CEO - ServicesJanuary 2010 to present
Daniel J. Cregg5457Executive Vice President (EVP) and CFO (PSEG)Chief Financial Officer (CFO) - PSEGOctober 2015 to present
Executive Vice PresidentEVP and CFO (PSE&G)- PSE&GOctober 2015 to present
Executive Vice PresidentEVP and CFO (Power)- PSEG PowerOctober 2015 to present
Vice President-Finance (PSE&G)June 2013 to October 2015
Ralph A. LaRossa57Vice President-Finance (Power)COB - PSEG Long Island LLCDecember 20112020 to June 2013present
David M. Daly56President and Chief Operating Officer (PSE&G)(COO) - PSEGJanuary 2020 to present
President and COO - PSEG PowerOctober 2017 to present
Chairman of the Board ofPresident and COO - PSE&GOctober 2006 to October 2017
COB - PSEG Long Island LLCOctober 2017 to present
President and Chief Operating Officer (PSEG Long Island LLC)October 2013 to October 2017
Ralph LaRossaDavid M. Daly5459President and Chief Operating Officer (Power)- PSE&GOctober 2017 to present
President and Chief Operating Officer (PSE&G)COO of PSEG Utilities and Clean Energy Ventures - Services; President - PSE&GOctober 2006January 2020 to October 2017December 2020
Chairman of the Board ofCOB - PSEG Long Island LLCOctober 2017 to December 2020
COO - PSE&GOctober 2017 to December 2019
President and COO - PSEG Long Island LLCOctober 2013 to October 2017
Derek M. DiRisio5356President (Services)- ServicesAugust 2014 to present
Vice President and Controller (PSEG)January 2007 to August 2014
Vice President and Controller (PSE&G)January 2007 to August 2014
Vice President and Controller (Power)January 2007 to August 2014
Vice President and Controller (Energy Holdings)January 2007 to August 2014
Vice President and Controller (Services)January 2007 to August 2014
Tamara L. Linde5356Executive Vice PresidentEVP and General Counsel (PSEG)- PSEGJuly 2014 to present
Executive Vice PresidentEVP and General Counsel (PSE&G)- PSE&GJuly 2014 to present
Executive Vice PresidentEVP and General Counsel (Power)- PSEG PowerJuly 2014 to present
Vice President - Regulatory (Services)December 2006 to July 2014
Rose M. Chernick57VP and Controller - PSEGMarch 2019 to present
Stuart J. Black55Vice PresidentVP and Controller (PSEG)- PSE&GAugust 2014March 2019 to present
Vice PresidentVP and Controller (PSE&G)- PSEG PowerAugust 2014March 2019 to present
Vice PresidentVP-Finance, Corporate Strategy and Controller (Power)Planning - ServicesAugust 2014November 2017 to presentMarch 2019
Vice President (Services)VP-Finance, Holdings and Assistant Controller (Power)Corporate Strategy and Planning - ServicesMarch 2010October 2015 to August 2014November 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.

GENERAL OPERATIONAL AND FINANCIAL RISKS
MARKET AND COMPETITION Inability to successfully develop, obtain regulatory approval for, or construct generation, transmission and distribution projects could adversely impact our businesses.
Our business plan calls for extensive investment in capital improvements and additions, including the construction and/or acquisition of T&D facilities and generation units; and modernizing existing infrastructure pursuant to investment programs entitled to current recovery. 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;
•complete such projects within budgets and on commercially reasonable terms and conditions;
•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
•at PSE&G, 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. Modifications to existing facilities may require us to install the best available control technology or to achieve the lowest achievable emission rates required by then-current regulations, which would likely result in substantial additional capital expenditures.
In addition, the successful operation of new or upgraded generation facilities or transmission or distribution projects is subject to risks relating to supply interruptions; work stoppages and labor disputes; weather interferences; unforeseen engineering and environmental problems, including those related to climate change; and the other risks described herein. 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 expected capacity or availability levels, which would adversely impact our financial condition and results of operations through lost revenue, increased expenses, higher maintenance costs and penalties.
Lack of growth or slower growth in the number of customers, or a decline in customer demand, which may not be fully addressed by our recently approved CIP, could adversely impact our financial condition, results of operations and cash flows.
Our CIP, which was recently approved by the BPU as part of our CEF-EE program, 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 to our current period revenue as compared to revenue thresholds established in our most recent distribution base rate proceeding. Recovery under the CIP is subject to certain limitations, including an actual versus allowed ROE test and ceilings on customer rate increases. The CIP does not address changes in the number of customers.
Growth in customer accounts and growth of customer usage each directly influence the demand for electricity and the need for additional transmission and distribution facilities. Customer growth and customer usage may be affected by a number of factors, including:
•the impacts of economic downturns, including increased unemployment and less demand from C&I customers;
•regulatory initiatives to reduce energy consumption or that favor certain fuel types;
•mandated energy efficiency measures;
•DSM tools;
•technological advances; and
•a shift in the composition of our customer base from C&I customers to residential customers.
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Some or all of these factors could result in a lack of growth or decline in customer demand for electricity and may prevent us from fully realizing the benefits from significant capital investments and expenditures, which could have a material adverse effect on our financial position, results of operations and cash flows.
We may be adversely affected by equipment failures, accidents, severe weather events, acts of war or terrorism 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 equipment failures, accidents, severe weather events, acts of war or terrorism or other incidents which could result in damage to or destruction of our facilities or damage to persons or property.
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 and 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, the physical risks of severe weather events, such as experienced from Superstorm Sandy and more recently Tropical Storm Isaias, and of climate change, changes in sea level, temperature and precipitation patterns and other related phenomena have further exacerbated these risks. 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 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 also materially damage our reputation.
Any inability to recover the carrying amount of our long-lived assets could result in future impairment charges which could have a material adverse impact on our financial condition and results of operations.
Long-lived assets represent approximately 75%, 82% and 65% of the total assets of PSEG, PSE&G and PSEG Power, respectively, as of December 31, 2020. Management evaluates long-lived assets for impairment whenever events or changes in circumstances, such as significant adverse changes in regulation, 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.
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 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 credit 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;
•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;
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•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.
Cybersecurity attacks or intrusions could adversely impact our businesses.
Cybersecurity threats to the U.S. energy market infrastructure are increasing in sophistication, magnitude and frequency, particularly since the COVID-19 pandemic and the resulting shift to virtual operations began. We rely on information technology systems that utilize sophisticated digital 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 oversighton 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 and the power grid,
•theft of confidential company, employee, shareholder, vendor or customer information, which may cause us to be in breach of certain covenants and contractual obligations, 
•general business system and process interruption or compromise, including preventing us from servicing our customers, collecting revenues or the ability to record, process and/or report financial information correctly, and
•breaches of vendors’ infrastructures where our confidential information is stored.
We and our third-party vendors have been and likely will continue to be subject to attempted cybersecurity attacks. While there has been no material impact on our business or operations from these attempted attacks, if a significant cybersecurity event or breach should occur within our company or with one of our material vendors, we could be exposed to significant loss of revenue, material repair costs to intellectual and physical property, significant fines and penalties for non-compliance with existing laws and regulations, significant litigation costs, increased costs to finance our businesses, damage to our reputation and loss of confidence from our customers, regulators, investors, vendors and employees. Similarly, a significant cybersecurity event or breach experienced by a competitor, regulatory authority, RTO, ISO, or vendor could also materially impact our business and results of operations via enhanced legal and regulatory requirements. For a discussion of state and federal cybersecurity regulatory requirements and information regarding our cybersecurity program, see Item 1. Business—Regulatory Issues.
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 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, including the long-term impact it 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 service 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 gas bad debts;
•decreased aggregate demand for generation and decreased C&I demand for PSE&G’s electric and gas service;
•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;
•our financial assets recorded at fair value, including the impact on Net Income from adjustments to fair value of investments in our pension and Nuclear Decommissioning Trust (NDT) Fund, and potential increases in the related funding requirements; and
•the availability of materials and supplies due to supply chain interruptions.
We continue to implement strong physical and cybersecurity measures to ensure that our systems remain functional in order to both serve our operational needs with a remote workforce and ensure uninterrupted service to our customers. Any failure or breach of these systems would have a material impact on our business and results of operations.
Covenants in our debt instruments may adversely affect our operations.
PSEG’s, PSE&G’s and PSEG Power’s 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 and PSEG Power’s bank credit agreements, certain change of control events. PSEG Power’s bank credit agreements and outstanding notes also contain limitations on the incurrence of subsidiary debt and liens and certain of PSEG Power’s outstanding notes require PSEG Power to repurchase such notes upon certain change of control events. 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 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 decommissioning trust. Failure to adequately manage 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
The timeline and ultimate outcome of our exploration of strategic alternatives relating to PSEG Power’s non-nuclear generating fleet is uncertain.
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 primarily regulated electric and gas utility, with a contracted generation business.
Since the announcement, we have engaged in preparatory activities relating to the potential divestiture of, and begun the marketing processes for these assets. The timeline and ultimate outcome of this process are uncertain. Our ability to divest all or
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a portion of these assets, and the applicable terms, conditions and timeline, will depend in large part on the participation of potentially interested parties and the value such parties place on the applicable assets. It is possible that third parties may wish to acquire all, a portion or none of the applicable assets (or engage in another transaction not presently being pursued by us), and the value that such third parties may place on such assets is uncertain. We may encounter difficulty in finding buyers or alternative exit strategies on acceptable terms in a timely manner, or we may dispose of a business at a price or on terms that are less desirable than we had anticipated. The process may further be impacted by, among other things, global and domestic market and economic conditions, conditions generally impacting the fossil and solar generating industries and changes in the regulatory environment or other factors outside of our control. Any transaction agreement that we may enter into will contain various terms and conditions, and it is possible that even if entered into, such transaction may fail to be completed in a timely manner or at all. Any or all of these factors could have a material and adverse impact on our business prospects or results of operations.
PSEG Power’s existing credit agreements and senior notes contain covenants restricting the ability of PSEG Power and its subsidiaries that guarantee its indebtedness from consummating certain mergers, consolidations or asset sales. The disposal of PSEG Power’s non-nuclear generating fleet could, depending on the structure of such transaction, among other factors, trigger a default under one or more of these provisions. For these reasons, or for other reasons, PSEG Power may decide, or be required, to seek amendments or waivers under its credit agreements and may redeem its outstanding senior notes, at a price equal to the principal amount thereof plus a make-whole premium. Whether such amendments, waivers or redemptions will be required will depend on a number of factors, including the structure of any transaction resulting from the strategic review, and any actual redemption price would depend on the applicable treasury rate in effect at such time. It is likewise possible that the ultimate outcome of the process may result in a transaction, or may result in no transaction at all, where the Power notes are not redeemed. If PSEG Power is required to redeem its senior notes, the cost of such redemption would be material.
PSEG Power performed a recoverability test for impairment of certain of its generating assets using a weighted probability cash flow analysis that considers the likelihood of a potential sale or disposition or continuing to operate the assets through their remaining estimated useful lives. As of December 31, 2020, the estimated undiscounted future cash flows of each of the asset groups exceeded the carrying amount and no impairment was identified. However, certain assumptions are subject to change as the potential sales and marketing process progresses. Management expects that a change in the probability of a successful disposition or to a held-for sale classification from a held-for-use classification would have a material adverse impact on PSEG’s and PSEG Power’s future financial results.
Failure to complete, or delays in completing, our proposed investment in the Ocean Wind project could adversely affect our business and prospects. In addition, following the completion of our initial investment in the project, there are numerous operational risks and uncertainties associated with, and we may fail to realize the anticipated strategic and financial benefits of, the Ocean Wind project.
In December 2020, we entered into a definitive agreement with Ørsted North America Inc. (“Ørsted”) pursuant to which we agreed to acquire a 25% interest in the 1,100-megawatt Ocean Wind project from Ørsted. The completion of our initial investment in the Ocean Wind project is subject to certain closing conditions, including, among others, approval by the BPU. While we currently anticipate that the investment will close in the first half of 2021, we cannot predict whether any of the required closing conditions will be satisfied or waived in a timely manner or at all.
Following the completion of our initial investment in the Ocean Wind project, our ability to realize the anticipated strategic and financial benefits of the project 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 in connection with the project;
•the risk that there may be changes to the tax laws, rules and interpretations applicable to the project, including the risk of any reduction, elimination or expiration of government incentives for wind energy or otherwise that may adversely affect the 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 thedevelopment, construction and operation of the project, as well as other risks and uncertainties inherent in joint venture arrangements;
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•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 the Ocean Wind 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.
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 and coal generation costs have not declined similarly.
PSEG and Power continue to monitor their remaining coal assets, including the Keystone and Conemaugh generating stations, to ensure their economic viability through the end of their designated useful lives and their continued classification as held for use. The precise timing of a change in useful lives may be dependent upon events out of PSEG’s and Power’s control and may impact our ability to operate or maintain these assets in the future. These generating stations may be impacted by factors such as continued depressed wholesale power prices or capacity factors, among other things. Any early retirement of these coal units before the end of their current estimated useful lives or change in the classification as held for use may have a material adverse impact on PSEG’s and Power’s future financial results.
The decline in market prices of energy, resulting from low natural gas prices driven by the growth of shale gas production since 2007, the continuing cost of regulatory compliance and enhanced security for nuclear facilities, both federal and state-level policies that provide financial incentives to construct renewable energy such as wind and solar and the failure to adequately compensate nuclear generating stations for the attributes they bring similar to renewable energy production have been contributing factors to the significantly reduced revenues from nuclear generating stations while simultaneously raising the unit cost of production.
In the ordinary course, management, and in the case of the Salem units the co-owner, each makes a number of decisions that impact the operation of our nuclear units beyond the current year, including whether and to what extent these units participate in RPM capacity auctions, commitments relating to refueling outages and significant capital expenditures, and decisions regarding our hedging arrangements. When considering whether to make these future commitments, management’s decisions will primarily be influenced by the financial outlook of the units, including the progress, timing and continued outlook for enactment of proposed legislation in the state of New Jersey. We cannot predict whether the legislation will be enacted or, if enacted, whether our nuclear generating stations in New Jersey will be selected or whether the legislation will provide a sufficient safety net for the continued operation of nuclear generating stations in New Jersey.
If market prices continue to be depressed and legislation is not enacted that adequately compensates nuclear generating stations for their attributes, Power anticipates it will no longer be covering its costs nor be adequately compensated for its market and operational risks at the Salem and Hope Creek nuclear units and would anticipate retiring these units early. The costs associated with any such retirement, which may include, among other things, accelerated depreciation and amortization or impairment charges, accelerated asset retirement costs, severance costs, environmental remediation costs and additional funding of the Nuclear Decommissioning Trust Fund (NDT) would be material to both PSEG and Power.
We may be unable to obtain an adequate fuel supply in the future.
We obtain substantially all of our physical natural gas coal 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 transportation agreements, balancing agreements, storage services financial hedging transactions and other contracts to ensure that the natural gas coal 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.
Additionally, the PJM power market has recently experienced an increase in natural gas-fired generation assets that supply electricity to the region. As a result, there has been a corresponding increase in the need for natural gas transportation assets to serve power generation assets. When extreme cold temperatures significantly increase the demand for natural gas used for residential heating, it can also create constraints on natural gas pipelines that serve power generation assets. When these conditions exist, it could interrupt the fuel supply to our natural gas-fired power plants in the PJM power market.
We are exposed to increases in the price of natural gas coal 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 coal

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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 coal 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 and force majeure. 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
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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.
In March 2017, WEC announced that it had filed for Chapter 11 bankruptcy in New York. WEC provides nuclear fuel fabrication services for Salem Units 1 and 2. In January 2018, Brookfield Business Partners LP announced its intention to acquire WEC. The acquisition is expected to close in 2018 if it receives the required approvals from the regulators and bankruptcy courts. No assurances can be given that the acquisition will be approved. In the event that WEC is unable to continue to provide fabrication services, we can provide no assurance that Power would be able to find alternative providers of such services in a timely manner or on acceptable terms. A failure by WEC to perform its obligations during the pendency of, or following its emergence from, bankruptcy 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.
Our inability to balance energy obligations with available supply could negatively impact results.
The revenues provided by the operationOperation 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;
quarterly and •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 isor 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.
We face significant competition in the wholesale energy and capacity markets.
Our wholesale power and marketing businesses are subject to significant competition that may adversely affect our ability to make investments or sales on favorable terms and achieve our business objectives. Increased competition could contribute to a reduction in prices offered for power and could result in lower earnings. Decreased competition could negatively impact results through a decline in market liquidity. Regulatory, environmental, industry and other operational developments will have a significant impact on our ability to compete in energy and capacity markets, potentially resulting in erosion of our market share and impairment in the value of our power plants. Recently, certain states have taken, or are considering taking, actions to subsidize or otherwise provide economic support to renewables, energy efficiency initiatives and existing, uneconomic generation facilities that could adversely affect capacity and energy prices. Increased generation supply and lower energy prices due to these subsidies could have an adverse impact on our results of operations.
The introduction or expansion of technologies related to energy generation, distribution and consumption and changes in customer usage patterns and 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 allowed forfacilitated the penetration of competing technologies, such as wind, solar, and commercial-sized power storage. Additionally, the development of DSM tools and practicesenergy efficiency programs can impact peak 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 tools and practicesenergy 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. Additionally, technologicalTechnological 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.
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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. SuchThese 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

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revenues, increased operating and maintenance expenses, and increased capital expenditures, as well as potential asset impairment charges or accelerated depreciation and decommissioning expenses over shortened remaining asset useful lives.
Economic downturns would likely have a material adverse effect on our businesses.
Our results of operations may be negatively affected by sustained downturns or sluggishness in the economy, including low levels in the market prices for power, generation capacity and natural gas, which can fluctuate substantially. Increased unemployment of residential customers and decreased demand for products and services provided by commercial and industrial customers resulting from an economic downturn could lead to declines in the demand for energy and an increase in the number of uncollectible customer balances, which would negatively impact our overall sales and cash flows. Although our utility business is subject to regulated allowable rates of return, overall declines in electricity and gas sold could materially adversely affect our financial condition, results of operations and cash flows. Additionally, prolonged economic downturns that negatively impact our financial condition, results of operations and cash flows could result in future material impairment charges to write down the carrying value of certain assets to their respective fair values.
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 by these counterparties could require PSEG Power to purchase or sell energy or fuel in the wholesale markets at less favorable prices and incur additional losses, which could have a material adverse impact on our results of operations, cash flows and financial position. In the spot markets, we are exposed to the risks of the default sharing mechanisms that exist in those markets, some of which attempt to spread the risk across all participants. Therefore, a default by a third party could increase our costs, which could negatively impact our results of operations and cash flows.
Financial market performance directly affectsThere 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 asset valuesoutput 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 nuclear decommissioning trust fundsplants 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 defined benefit plan trust funds. Market performance
•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 other factorscorrecting 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 decrease the value of trust assetsbe substantial and could result in the need for significant additional funding.
The performance of thehave a material adverse effect on our 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 nuclear decommissioning trust funds could increase 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 and other postretirement benefit (OPEB) 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 decommissioning trust. Failure to adequately manage our investments in our nuclear decommissioning trust 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 ourcondition, results of operations and cash flowsflows.
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.
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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 position.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, and failure to comply with these regulations could have a material adverse impact on PSE&G’s ability to operate its business and could result in fines, penalties or sanctions. The retail rates for electric and gas distribution services are established in a base rate caseproceeding and remain in effect until a new base rate caseproceeding is filed and concluded. In January 2018, PSE&G filed a distribution base rate case proceeding. 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.
Efforts designed to promoteIn September 2020, the BPU ordered the commencement of a comprehensive affiliate and expand the usemanagement audit of energy efficiency measures and distributed generation technologies, such as rooftop solar and battery storage, in PSE&G’s service territories could result in customers leaving the electric distribution system and an increase in customer net energy metering. Over time, customer adoption of these and other technologies and

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increased energy efficiency could adversely impact PSE&G’s revenue and ability to fully recover its costs, which could require PSE&G to pursue a rate case to adjust revenue requirements or seek recovery though other mechanisms.
&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 result in fines, a reduction in PSE&G’s authorized base rate or the disallowance of the recovery of certain costs, which could have a materiallymaterial adverse impact on 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 periodically files base rate case proceedings. Such proceedings are at times contentious, lengthy and subject to appeal, which could lead to uncertainty as to the ultimate results and which could introduce time delays in effectuating rate changes.
PSE&G periodically files base rate case proceedings with the BPU. In particular, in January 2018, PSE&G filed a distribution base rate case proceeding. These proceedings typically involve multiple parties, including governmental bodies and officials, consumer advocacy groups and various consumers of energy, who have differing concerns but who have the common objective of limiting rate increases or even reducing rates. The proceedings generally have timelines that&G’s proposed investment programs may not be limitedfully approved by statute. Decisionsregulators, 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 appeal, potentially leadingreview in the FERC-approved PJM transmission expansion process while distribution and clean energy projects are subject to additional uncertainty associated withapproval 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 proceedings. The potential durationfails to allow for the timely recovery of such proceedings createsall of PSE&G’s costs, including a risk that rates ultimately approved by the applicable regulatory body may not be sufficient forreturn of, or on, its investment, PSE&G will have a lower than anticipated rate base, thus causing its future earnings to recover its costs bybe lower than anticipated. If these programs are not approved, that could also adversely affect our service levels for customers. Further, the time the rates become effective. Established rates are also subjectBPU could take positions to subsequent reviews by state regulators, whereby various portionsexclude or limit utility participation in certain areas, such as renewable generation, energy efficiency, electric
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vehicle infrastructure and energy efficiency, demand responsestorage, which would limit our relationship with customers and renewable energy programs. If the base rate case proceeding is protracted or results in approved rates that do not allow PSE&G to fully recover its costs or result in ROEs that are below historical levels,narrow our financial condition, results of operations and cash flows would be materially adversely impacted.future growth prospects.
We are subject to comprehensive federal regulation that affects, or may affect, our businesses.
We are subject to regulation by federal authorities. Such regulation affects almost every aspect of our businesses, including management and operations; the terms and rates of transmission services; investment strategies; the financing of our operations and the payment of dividends. Failure to comply with these regulations could have a material adverse impact on our ability to operate our business and could result in fines, penalties or sanctions.
Recovery of wholesale transmission rates—PSE&G’s wholesale transmission rates are regulated by FERC and are recovered through a FERC-approved formula rate. The revenue requirements are reset each year through this formula.
In 2019 and 2020, FERC issued a series of orders that establish a new ROE policy for reviewing existing transmission ROEs. The methodology uses the DCF model, the CAPM and the risk premium model to determine if an existing base ROE is unjust and unreasonable and, if so, what replacement ROE is appropriate. In addition, ROE complaints have been pending before FERC, the ISO New England Inc. transmission ROEsowners and utilities in other jurisdictions. Over the past few years, several companies have recently becomenegotiated settlements that have resulted in reduced ROEs.
We are engaged in settlement discussions with the targetBPU Staff and the New Jersey Rate Counsel about the level of certain state utility commissions, municipal utilities, consumer advocates and consumer groups seeking to lower customer rates. These agencies and groups have filed complaints with FERC asking to reducePSE&G’s base transmission ROE; however, we cannot predict the base ROE of various transmission owners. They point to changes in the capital markets as justification for lowering the ROEoutcome of these companies.settlement discussions.
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 we are notOrder 1000 retains limited carve-outs for certain projects that will continue to default to incumbents for construction responsibility, including immediately needed reliability projects, upgrades to existing transmission facilities, 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 of any of these complaints, they could set a precedent for FERC-regulated transmission owners, such asto recovery by PSE&G. Inability to obtain fair or timely recovery of all our costs, including a return of or on our investments in rates,&G under its rate base, which could have a material adverse impact on our business. financial condition and results of operations.
North American Electric Reliability Council (NERC)NERC Compliance—Mandatory NERC, at the direction of FERC, has implemented mandatory NERC Operations and Planning and Critical Infrastructure Protection standards have been established to ensure the reliability of the U.S.North American Bulk Electric System, which includes electric transmission and generation systemsystems, and to prevent major system black-outs.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. An audit of PSE&G’s compliance with Critical Infrastructure Protection physical and cybersecurity standards was performed in the fourth quarter of 2018 and again in the third quarter of 2020, the results of which are under review. We cannot determine what actions, if any, NERC or FERC may take. Failure to comply with such standards could result in penalties or increased costs to bring such facilities into compliance. Such penalties and costs, as well as lost revenue from prolonged outages required to bring facilities into compliance with these standards, could materially adversely impact our business, results of operations and cash flows.
Market-Based Rate (MBR)MBR Authority and Other Regulatory Approvals—Under FERC regulations, public utilities that wish to sell power at market rates must receive MBR Authorityauthority 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 may 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.

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In November 2017, FERC issued an order accepting the triennial filing made by the PSEG companies seeking authority to sell energy, capacity and ancillary services at market-based rates.
Oversight by the Commodity Futures Trading Commission (CFTC)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 position limits on 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 more fully described in Item 7. MD&A—Executive Overview of 2020 and Future Outlook, in April 2019, PSEG Power’s
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Salem 1, Salem 2 and Hope Creek nuclear plants were awarded ZECs by the BPU. 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.
The BPU’s decision awarding ZECs has been appealed by the New Jersey Rate Counsel. PSEG cannot predict the outcome of this matter.
In October 2020, PSEG Power filed with the BPU its ZEC applications for Salem 1, Salem 2 and Hope Creek for the three-year eligibility period starting in June 2022.
In the event that (i) the ZEC program is overturned or is otherwise materially adversely modified through legal process, (ii) the amount of ZEC payments that may be awarded or other terms and conditions of the second ZEC eligibility period proposed by the BPU in its final decision differ from those of the current ZEC period; or (iii) any of the Salem 1, Salem 2 and Hope Creek plants is not awarded ZEC payments by the BPU and does not otherwise experience a material financial change, PSEG Power will take all necessary steps to cease to operateall of these plants. Alternatively, if all of the Salem 1, Salem 2 and Hope Creek plants are selected to continue to receive ZEC payments but 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 CWA and related state regulations, or other factors, PSEG Power will take all necessary steps to cease to operate all of these plants and will incur associated costs and accounting charges. These may include, among other things, one-time impairment charges or accelerated Depreciation and Amortization expense on the remaining carrying value of the plants, potential penalties associated with the early termination of capacity obligations and fuel contracts, accelerated asset retirement costs, severance costs, environmental remediation costs and, in certain circumstances, potential additional funding of the NDT Fund, which would be material to both PSEG and PSEG Power.
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 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 2020 and Future Outlook.
Further, some of the market-based mechanisms in which we participate, including BGS auctions, 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.
Approximately 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. TheseIn 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 but 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. In addition, the on-site storage for spent nuclear fuel may significantly increase the decommissioning costs of our nuclear units.
Regulatory and Legal Risk—We may be required to substantially increase capital expenditures or operating or
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decommissioning costs at our nuclear facilities to the extent 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 facilitiesfacilities; or the shutdown of one of our nuclear facilities. Any such event could have a material adverse effect on our financial positioncondition or results of operations.
Operational Risk—Operations at any of our nuclear generating unitsfacilities could degrade to the point where thean affected unit needs to be shut down or operated at less than full capacity. If this were to happen, identifying and correcting the causes may require significant time and expense. Any significant outages could result in reduced earnings as we would needhave less electric output to purchase or generate higher-priced energy to meet our contractual obligations.sell.
In addition, if a stationunit 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 alsolead 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 aan industry nuclear incident or retroactiveretrospective premiums due to adverse industry loss experience.experience and such assessments may be material.
In the event of non-compliance with applicable legislation, regulation and licenses, the NRC may increase regulatory 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 commercially 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 thea nuclear facility at the end of its useful life. PSEG Nuclear has established a Nuclear Decommissioning Trust (NDT)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

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current estimates. If we determine that it is necessary to retire one of our nuclear generating stations before the end of its useful life, there is a risk that it will no longer meet the NRC minimum funding requirements due to the earlier commencement of decommissioning activities and a shorter time period over which the NDT investments could appreciate in value. A shortfall could require PSEG to post parental guarantees or make additional cash contributions to ensure that the NDT Fund continues to satisfy the NRC minimum funding requirements. As a result, our financial position or cash flows could be significantly adversely affected.
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 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. Because much of our generation has historically been located in constrained areas in PJM and ISO-NE, the existence of these rules has had a positive impact on our revenues. PJM’s capacity market design rules and ISO-NE’s forward capacity market rules continue to evolve, most recently in response to efforts to integrate public policy initiatives into the wholesale markets. Any changes to these rules may have an adverse impact on our financial condition, results of operations and cash flows.
We could also be impacted by a number of other events, including regulatory or legislative actions such as direct and indirect subsidies, favoring certain types of resources and/or technologies. Further, some of the market-based mechanisms in which we participate, including BGS auctions, 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, 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.
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, the impact on globalof climate change, natural resourcesresource damages and other matters. These laws and regulations affect the manner in whichhow we conduct our operations and make capital expenditures. There have been a number of recent changes to existing environmental laws and regulations and this trend may continue. We expect there will be changes to existing environmental laws and regulations, particularly in light of the change in administration following the 20162020 U.S. presidential election. Changes in these laws, or violations of laws, could result in significant increases in our compliance costs, capital expenditures to bring our 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.
Environmental laws and regulations have generally become more stringent over time, and this trend is likely to continue. In particular:
Concerns over global climate change could result inFor a further discussion of environmental laws and regulations to limit CO2 emissions or other GHG emissions produced byimpacting our fossil generation facilities—Federal and state legislation and regulation designed to address global climate change through the reduction of GHG emissions could materially impact our fossil generation facilities. For example, in 2015 the EPA published new rules for both new and existing power plants. While the EPA recently repealed these rules for existing power plants, actions by northeastern states, including New Jersey, could have cost implications for our fossil generation facilities. Such expenditures could materially affect the continued economic viability of one or more such facilities.
In addition to legislative and regulatory initiatives, the outcome of certain legal proceedings regarding alleged impacts of global climate change not involving us could be material to the future liability of energy companies. If relevant federal or state common law were to develop that imposed liability upon those that emit GHGs for alleged impacts of GHGs emissions, such potential liability to our fossil generation operations could be material.
Potential closed-cycle cooling requirements—In 2014, the EPA finalized rules regarding the regulation of cooling water intake structures. The EPA has structured the rule so that each state will continue to consider renewal permits for existing power facilities on a case by case basis. The rule requires that facilities seeking permit renewals conduct a wide range of studies

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related to impingement mortality and entrainment and submit the results with their permit applications. State actions to renew permits under the provisions of this rule are ongoing at this time.
If the NJDEP or the CTEEP were to require installation of closed-cycle cooling or its equivalent at any of our Salem, Bridgeport or New Haven generating stations, the related increased costs and impacts would be material to our financial position,business, results of operations and cash flowsfinancial condition,
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including the impact of federal and would require further economic reviewstate laws and regulations relating to determine whether to continue operations or decommission any such station.
RemediationGHG emissions and remediation of environmental contamination, at current or formerly-owned facilities—We are subject to liability under environmental laws for the costs of remediating environmental contamination of property now or formerly owned by us and of property contaminated by hazardous substances that we generated. Remediation activities associated with our former Manufactured Gas Plant (MGP) operations are one source of such costs. In addition, the historic operations of our 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 variousstatutes. The EPA is also evaluating the Hackensack River, a tributary to Newark Bay, for inclusion in the Superfund program. We are also 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, the related costs of which could have a material adverse effect on our financial condition, results of operations and cash flows. New Jersey law places affirmative obligations on us to investigate and, if necessary, remediate contaminated property upon which we were in any way responsible for a discharge of hazardous substances, impacting the speed by which we will need to investigate contaminated properties, which could adversely impact cash flows. We cannot predict what further actions, if any, or the costs or the timing thereof, that may be required with respect to these or other natural resource damages claims. However, exposure to natural resource damages could subject us to additional potentially material liability. For a discussion of these and other environmental matters, see Item 1. Environmental Matters and Item 8. Financial Statements and Supplementary Data—Note 13.15. 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.
We cannot predict the outcome of any legal, regulatory or other proceeding, settlement, investigation or claim relating to our business activities. An adverse determination could negatively impact our financial condition, results of operations and cash flows.
From time to time we are involved in legal, regulatory and other proceedings or claims arising out of our business operations, the most significant of which are summarized in Item 8. Financial Statements and Supplementary Data—Note 13. Commitments and Contingent Liabilities. Adverse outcomes in any of these proceedings could require significant expenditures that could have a material adverse effect on our financial condition, results of operations and cash flows.
In particular, as previously disclosed, Power has discovered that it incorrectly calculated certain components of its cost-based bids for its New Jersey fossil generating units in the PJM energy market. Upon discovery of the errors, PSEG retained outside counsel to assist in the conduct of an investigation into the matter and self-reported the errors to FERC, PJM and the PJM Independent Market Monitor (IMM). FERC Staff initiated a preliminary, non-public staff investigation into the matter, which is ongoing. We are unable to reasonably estimate the range of possible loss for this matter; however, the amounts of potential disgorgement and other potential penalties that Power may incur span a wide range depending on the success of PSEG’s legal arguments. If we do not prevail in whole or in part with FERC or in a judicial challenge that we may choose to pursue, it is likely that Power would record additional losses and that such additional losses would be material to our results of operations.





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Changes in tax law and regulation and the inherent difficulty in quantifying potential tax effects of business decisions could negatively impact our results of operations and cash flows.
In December 2017, the Tax Act was enacted, which made significant changes to U.S. tax law. Among other things, under the Tax Act, the statutory U.S. corporate income tax rate decreased from a maximum of 35% to 21%, effective January 1, 2018, and certain changes were made to bonus depreciation rules. However, the Tax Act is unclear in certain respects and will require interpretations and implementing regulations by the Internal Revenue Service (IRS), as well as state tax authorities, and the Tax Act could be subject to potential amendments and technical corrections. We cannot assess the impact that any such interpretations, regulations, amendments or corrections could have on our results of operations or financial condition. In addition, the regulatory treatment of certain impacts of the Tax Act will be subject to the discretion of FERC and the state regulators which we are unable to determine at this time.
We are subject to the provisions of the Financial Accounting Standards Board (FASB) Accounting Standards Codification 740, Income Taxes (ASC 740), which requires that the effect on deferred tax assets and liabilities of a change in tax rates be recognized in the period the tax rate change was enacted. The impact of the rate change in 2017’s financial statements is discussed in Item 8. Financial Statements and Supplementary Data—Note 20. Income Taxes.
We do not have the necessary information available, prepared, or analyzed (including computations) in reasonable detail to complete the accounting under ASC 740 for certain income tax effects of the Tax Act for the reporting period in which the Tax Act was enacted. Accordingly, the amounts recognized in the current reporting period should be considered provisional, in accordance with SEC Staff Accounting Bulletin No. 118, and any revisions to these amounts could be material.
Further, the Tax Act is unclear in certain respects and will require interpretations and implementing regulations by the Internal Revenue Service (IRS), as well as state tax authorities. The Tax Act could also be subject to potential amendments and technical corrections which could impact PSEG, PSE&G and Power’s financial statements.
In addition, we are required to make judgments in order to estimate our obligations to taxing authorities. These tax obligations include income, real estate, sales and use and employment-related taxes. These judgments can include reserves for potential adverse outcomes regarding tax positions that have been taken that could be subject to challenge by the tax authorities. If our actual tax obligations materially differ from our estimated obligations, our results of operations and cash flows could be materially adversely affected.
OPERATIONAL RISKS
Because PSEG is a holding company, its ability to meet its corporate funding needs, service debt and pay dividends could be limited.
PSEG is a holding company with no material assets other than the stock or membership interests of its subsidiaries. Accordingly, all of the operations of PSEG are conducted by its subsidiaries, which are separate and distinct legal entities that have no obligation, contingent or otherwise, to pay the debt of PSEG or to make any funds available to PSEG to pay such debt or satisfy its other corporate funding needs. These corporate funding needs include PSEG’s operating expenses, the payment of interest on and principal of its outstanding indebtedness and the payment of dividends on its capital stock. As a result, PSEG can give no assurances that its subsidiaries will be able to transfer funds to PSEG to meet all of these obligations.
Lack of growth or slower growth in the number of customers, or a decline in customer demand, could adversely impact our financial condition, results of operations and cash flows.
Growth in customer accounts and growth of customer usage each directly influence demand for electricity and the need for additional generation, transmission and distribution facilities. Customer growth and customer usage may be affected by a number of factors, including:
regulatory incentives to reduce energy consumption;
mandated energy efficiency measures;
demand-side management tools;
technological advances; and
a shift in the composition of our customer base from commercial and industrial customers to residential customers.
Some or all of these factors could result in a lack of growth or decline in customer demand for electricity and may prevent us from fully realizing the benefits from significant capital investments and expenditures, which could have a material adverse effect on our financial position, results of operations and cash flows.

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There may be periods when Power may not be able to meet its commitments under forward sale obligations at a reasonable cost or at all.
A substantial portion of Power’s generation output has been sold forward under fixed price power sales contracts and 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, 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 agreements are not contingent on a unit being available to generate power, 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 Power does not have sufficient lower cost capacity to meet its commitments under its forward sale obligations, Power would be required to supply replacement power either by running its other higher cost power plants or by obtaining power from third-party sources at market prices that could substantially exceed the contract price. This could have a material adverse effect on our financial condition, results of operations and cash flows. If Power fails to deliver the contracted power, it would be required to pay the difference between the market price at the delivery point and the contract price, and the amount of such payments could be substantial.
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. Our 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 forego 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 expansion of transmission infrastructure. We also cannot predict whether transmission facilities will be expanded 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.
A portion of our generation is located in load pockets. Expansion of transmission systems to reduce or eliminate these load pockets could negatively impact the value or profitability of our existing generation facilities in these areas.
Inability to successfully develop or construct generation, transmission and distribution projects could adversely impact our businesses.
Our business plan calls for extensive investment in capital improvements and additions, including the installation of required environmental upgrades and retrofits; construction and/or acquisition of additional generation units and transmission and distribution facilities; and modernizing existing infrastructure pursuant to investment programs entitled to current recovery. 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;

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obtain environmental permits and approvals;
obtain community support for such projects to avoid delays in the receipt of permits and approvals from regulatory authorities;
complete such projects within budgets and on commercially reasonable terms and conditions;
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
at PSE&G, 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. Further, any unexpected failure of our existing facilities, including failure associated with breakdowns, forced outages or any unanticipated capital expenditures could result in reduced profitability. Modifications to existing facilities may require us to install the best available control technology or to achieve the lowest achievable emission rates required by then-current regulations, which would likely result in substantial additional capital expenditures.
In addition, the successful operation of new or upgraded generation facilities or transmission or distribution projects is subject to risks relating to supply interruptions; work stoppages and labor disputes; weather interferences; unforeseen engineering and environmental problems, including those related to climate change; and the other risks described herein. 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 expected capacity or availability levels, which would adversely impact our financial condition and results of operations through lost revenue, increased expenses, higher maintenance costs and penalties.
FERC Order 1000 has generally opened transmission development to competition from independent developers, allowing such developers to compete with incumbent utilities for the construction and operation of transmission facilities in its service territory. While Order 1000 retains limited carve-outs for certain projects that will continue to default to incumbents for construction responsibility, including immediately needed reliability projects, upgrades to existing transmission facilities, projects cost-allocated to a single transmission zone, and projects being built on existing rights-of-way and whose construction would interfere with incumbents’ use of their 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. In addition, certain PJM cost allocation determinations have been recently challenged at FERC, the resolution of which could impact costs borne by New Jersey ratepayers and increase customer bills.
We may be adversely affected by equipment failures, accidents, severe weather events or other incidents 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 equipment failures, accidents, severe weather events, or other incidents which could result in damage to or destruction of our facilities or damage to persons or property. For instance, equipment failures in our natural gas distribution could give rise to a variety of hazards and operating risks, such as leaks, accidental explosions and mechanical problems, which could cause substantial financial losses and harm our reputation.
In addition, the physical risks of severe weather events, such as experienced from Hurricane Irene and Superstorm Sandy, and of climate change, changes in sea level, temperature and precipitation patterns and other related phenomena have further exacerbated these risks. 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/penalties; and increase the level of oversight of our utility and generation operations and infrastructure through investigations or through the imposition of additional regulatory or legislative requirements. Such actions could adversely affect our costs, competitiveness and future investments, which could be material to our financial position, results of operations and cash flow. For our transmission and distribution business, the cost of storm restoration efforts may not be fully recoverable through the regulatory process.
We own less than a controlling interest in some of our generating facilities.
We have limited control over the operation of some of our generating facilities, including the Keystone, Conemaugh and Peach Bottom facilities, because our investments represent less than a controlling interest. We seek to exert a degree of influence with respect to the management and operation of projects in which we own less than a controlling interest by negotiating to obtain positions on management committees or to receive certain limited governance rights. However, we may not always succeed in such negotiations. As a result, we may be dependent on our partners to operate such facilities. The approval of our partners also

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may be required for us to transfer our interest in such projects. Reliance on our partners for the management and operation of these facilities could result in a lower return on these facilities than what we believe we could have otherwise achieved.
Any inability to recover the carrying amount of our long-lived assets and leveraged leases 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 74%, 81% and 69% of the total assets of PSEG, PSE&G and Power, respectively, as of December 31, 2017. Management evaluates long-lived assets for impairment whenever events or changes in circumstances, such as significant adverse changes in regulation 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.
Energy Holdings has investments in domestic energy and real estate assets subject primarily to leveraged lease accounting. A leveraged lease is typically comprised of an investment by an equity investor and debt provided by a third-party debt investor. As an equity investor, Energy Holdings’ equity investments in the leases are comprised of the total expected lease receivables over the lease terms plus the estimated residual values at the end of the lease terms, reduced for any income not yet earned on the leases. Our receipt of payments related to our leveraged lease portfolio in accordance with the lease contracts can be impacted by various factors, including new environmental legislation regarding air quality and other discharges in the process of generating electricity; market prices for fuel and electricity, including the impact of low gas prices on our coal generation investments; overall financial condition of lease counterparties; and the quality and condition of assets under lease.
During 2016, due to the adverse economic conditions experienced by coal generation in PJM, Energy Holdings recorded pre-tax write-downs relating to the NRG REMA, LLC (REMA) leveraged leases in the aggregate of $147 million. During 2017, due to continuing liquidity issues facing REMA, economic challenges facing coal generation in PJM, and based upon an ongoing review of available alternatives as well as certain discussions with REMA management, Energy Holdings recorded additional pre-tax charges of $77 million in the aggregate.
In June 2017, GenOn Energy, Inc. (GenOn) and certain of its subsidiaries filed voluntary petitions for relief under Chapter 11 of the United States Bankruptcy Code. REMA was not included in the GenOn filing. Energy Holdings continues to monitor the restructuring of GenOn and its possible impacts on REMA and continues to discuss the situation with various parties relevant to this matter. PSEG cannot predict the outcome of GenOn’s efforts to restructure its portfolio and improve its liquidity and the possible related impact on REMA. PSEG continues to monitor any changes to REMA’s and GenOn’s status and potential impacts on Energy Holdings’ lease investments, which could include further write-downs of the values of Energy Holdings’ leveraged leases.
There can be no assurance that a continuation or worsening of the adverse economic conditions would not lead to additional write-downs at any of our other generation units in our leveraged lease portfolio, and such write-downs could be material
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 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 credit 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;
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

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maintenance of our investment grade credit ratings.
Market disruptions, such as economic downturns experienced in the U.S. and abroad in recent years, the bankruptcy of an unrelated energy company, changes in market prices for electricity and gas, and actual or threatened 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 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.
We may be unable to realize anticipated tax benefits or retain existing tax credits.
The deferred tax assets and tax credits of PSEG, PSE&G or Power are evaluated for ultimate ability to realize these assets. A valuation allowance may be recorded against the deferred tax assets if we estimate that such assets are more likely than not to be unrealizable based on available evidence including cumulative and forecasted pretax book earnings at the time the estimate is made. A valuation allowance related to deferred tax assets or the monetization of tax credits can be affected by changes to tax laws, statutory tax rates and future taxable income levels. In the event that we determine that we would not be able to realize all or a portion of our deferred tax assets in the future or the benefit of tax credits, we would reduce such amounts through a charge to income tax expense in the period in which that determination was made, which could have a material adverse impact on our financial condition and results of operations.
Challenges associated with recruitment and/or retention of key executives and a skilled workforce could adversely impact our businesses.
Our operations depend on the recruitment and retention of key executives and a skilled workforce. The loss or retirement of key executives or other employees, including those with the specialized knowledge required to support our generation, transmission and distribution operations, could result in various operational challenges. Certain events, such as the potential for early retirement of our nuclear facilities, can make it more difficult to retain these employees. We may incur increased costs for contractors to replace employees, and the loss of institutional and industry knowledge and the increased costs to hire and lengthy time to train new personnel could result in lower productivity, resulting in increased costs, which would negatively impact our results of operations. This has the potential to become more critical as a growing number of employees become eligible to retire.
As of December 31, 2017, approximately 62% of our employees were covered by collective bargaining agreements. As a result, our success will depend on our ability to successfully renegotiate these agreements as they expire. Inability to do so may result in employee strikes or work stoppages which would disrupt our operations and could also result in increased costs, all of which could have a material adverse effect on our business, financial condition, results of operations and cash flows.
Covenants in our debt instruments may adversely affect our operations.
PSEG’s, PSE&G’s and Power’s 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 and Power’s bank credit agreements, certain change of control events. Power’s bank credit agreements and outstanding notes also contain limitations on the incurrence of subsidiary debt and liens and Power’s outstanding notes require Power to repurchase such notes upon certain change of control events. 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.
Cybersecurity attacks or intrusions could adversely impact our businesses.
Cybersecurity threats to the U.S. energy market infrastructure are increasing in sophistication, magnitude and frequency. We rely on information technology systems that utilize sophisticated digital systems and network infrastructure to operate our generation, transmission and distribution systems. We also store sensitive data, intellectual property and proprietary or personally identifiable information regarding our business, employees, shareholders, customers and vendors on our systems and conduct power marketing and hedging activities. In addition, the operation of our business is dependent upon the information technology systems of third parties, including our vendors, regulators, RTOs and Independent System Operators (ISOs), among others. Our and third-party information technology systems may be vulnerable to cybersecurity attacks involving domestic or foreign sources. A cybersecurity attack may also leverage such information technology to cause disruptions at a third party. Cybersecurity impacts to our operations include:

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disruption of the operation of our assets and the power grid,
theft of confidential company, employee, shareholder, vendor or customer information, which may cause us to be in breach of certain covenants and contractual obligations, 
general business system and process interruption or compromise, including preventing us from servicing our customers, collecting revenues or the ability to record, process and/or report financial information correctly, and
breaches of vendors’ infrastructures where our confidential information is stored.
In late 2017, PSE&G learned that its customers may be affected by a potential data breach involving the systems of TIO Networks, a subsidiary of PayPal Holdings. PayPal notified PSE&G that there was unauthorized access to TIO Networks’ system that stores customer information. TIO Networks processed payments made at automated kiosks in PSE&G’s walk-in customer service centers between 2012 and 2017. TIO Networks also facilitated payments PSE&G customers made at third-party payment centers, such as local convenience stores, that accept utility bill payments. The account numbers and addresses for PSE&G’s approximately 2.5 million customers may have been exposed as a result of the suspected breach. Customers paying by check via kiosk at one of PSE&G’s Customer Service Centers also may have had their personal checking account number and routing number exposed. We continue to work with TIO Networks and PayPal to analyze the impact of this event. While we have experienced and expect to continue to experience actual or attempted cyber-attacks on our information technology systems, none of these incidents has had a material impact on our operations or financial condition. 
If a significant cybersecurity event or breach should occur within our company or with one of our material vendors, we could be exposed to significant loss of revenue, material repair costs to intellectual and physical property, significant fines and penalties for non-compliance with existing laws and regulations, significant litigation costs, increased costs to finance our businesses, reputational damage and loss of confidence from our customers, regulators, investors, vendors and employees. Similarly, a significant cybersecurity event or breach experienced by a competitor, regulatory authority, RTO, ISO, or vendor could also materially impact our business and results of operations via enhanced legal and regulatory requirements. For a discussion of state and federal cybersecurity regulatory requirements and information regarding our cybersecurity program, see Part 1, Item 1. Regulatory Issues.
The market for cybersecurity insurance is relatively new and coverage available for cybersecurity events may evolve as the industry matures. While we maintain insurance relating to cybersecurity events, such insurance is subject to a number of exclusions and may be insufficient to offset any losses, costs or damage we experience.
Acts of war or terrorism could adversely affect our operations.
Our businesses and industry may be impacted by acts and threats of war or terrorism. These actions could result in increased political, economic and 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, our infrastructure facilities, such as our generating stations, transmission and distribution facilities and information technology systems, could be direct or indirect targets or be affected by terrorist or other criminal activity. Such events could severely disrupt our business operations and prevent us from servicing our customers. New or updated security regulations may require us to make changes to our current measures which could also result in additional expenses.


ITEM 1B.    UNRESOLVED STAFF COMMENTS
PSEG, PSE&G and PSEG Power
None.

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ITEM 2.    PROPERTIES
Our subsidiaries own allAll of our owned physical property.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, 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. Financial Statements and Supplementary Data—Note 13.15. Commitments and Contingent Liabilities.
Generation Facilities
Power
As of December 31, 2017, Power’s share of installed fossil and nuclear generating capacity is shown in the following table:
             
 Name Location 
Total
Capacity
(MW)
 % Owned 
Owned
Capacity
(MW)
 
Principal
Fuels
Used
 
 Steam:           
 Sewaren NJ 445
 100% 445
 Gas 
 Keystone (A) PA 1,711
 23% 391
 Coal 
 Conemaugh (A) PA 1,711
 23% 385
 Coal 
 Bridgeport Harbor CT 383
 100% 383
 Coal 
 New Haven Harbor CT 448
 100% 448
 Oil/Gas 
 Total Steam   4,698
   2,052
   
 Nuclear:       
   
 Hope Creek NJ 1,180
 100% 1,180
 Nuclear 
 Salem 1 & 2 NJ 2,282
 57% 1,310
 Nuclear 
 Peach Bottom 2 & 3 (B) PA 2,450
 50% 1,225
 Nuclear 
 Total Nuclear   5,912
   3,715
   
 Combined Cycle:       
   
 Bergen NJ 1,229
 100% 1,229
 Gas/Oil 
 Linden NJ 1,274
 100% 1,274
 Gas/Oil 
 Bethlehem NY 790
 100% 790
 Gas 
 Kalaeloa HI 208
 50% 104
 Oil 
 Total Combined Cycle   3,501
   3,397
   
 Combustion Turbine:           
 Essex NJ 81
 100% 81
 Gas/Oil 
 Kearny NJ 456
 100% 456
 Gas/Oil 
 Burlington NJ 168
 100% 168
 Gas/Oil 
 Linden NJ 336
 100% 336
 Gas/Oil 
 New Haven Harbor CT 130
 100% 130
 Gas/Oil 
 Bridgeport Harbor CT 17
 100% 17
 Oil 
 Total Combustion Turbine   1,188
   1,188
   
 Pumped Storage:       
   
 Yards Creek (C) NJ 420
 50% 210
   
 Total Power Plants   15,719
   10,562
   
             
(A)Operated by GenOn Northeast Management Company.
(B)Operated by Exelon Generation.
(C)Operated by Jersey Central Power & Light Company.
As of December 31, 2017, Power also owned and operated 414 MW dc of photovoltaic solar generation facilities in various states.

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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, 2017,2020, PSE&G’s electric transmission and distributionT&D system included approximately 24,00025,000 circuit miles, and 853,000860,000 poles, of which 65%64% are jointly-owned. In addition, PSE&G owns and operates 5054 switching stations with an aggregate installed capacity of 36,02338,353 megavolt-amperes (MVA) and 244245 substations with an aggregate installed capacity of 8,2508,647 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, 2017,2020, 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 (LNG) and three liquid petroleum air gas (LPG) peaking facilities. The daily gas capacity of these peaking facilities (the maximum daily gas delivery available during the three peak winter months) is approximately 2.82.5 million therms in the aggregate.
Solar
As of December 31, 2017,2020, PSE&G had 123owned 158 MW dc of installed PV solar capacity throughout New Jersey.
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PSEG Power
Generation Facilities
As of December 31, 2020, 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
Steam:
Bridgeport Harbor 3 (A)CT383 100%383 Coal
New Haven HarborCT448 100%448 Oil/Gas
Total Steam831 831 
Nuclear:
Hope CreekNJ1,180 100%1,180 Nuclear
Salem 1 & 2NJ2,285 57%1,311 Nuclear
Peach Bottom 2 & 3 (B)PA2,549 50%1,275 Nuclear
Total Nuclear6,014 3,766 
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
BethlehemNY817 100%817 Gas
KalaeloaHI208 50%104 Oil
Total Combined Cycle5,353 5,249 
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
Bridgeport Harbor 4CT17 100%17 Oil
Total Combustion Turbine1,188 1,188 
Total PSEG Power Plants13,386 11,034 
(A)Plan to early retire in 2021.
(B)Operated by Exelon Generation.
As of December 31, 2020, PSEG Power also owned and operated 467 MW dc of PV solar generation facilities in various states.

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. Financial Statements and Supplementary Data—Note 13.15. 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 16, 2018,19, 2021, there were 60,86854,220 registered holders.
The following graph below shows a comparison of the five-year cumulative return assuming $100 invested on December 31, 20122015 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.
 
               
   2012 2013 2014 2015 2016 2017 
 PSEG $100.00
 $109.35
 $146.73
 $142.46
 $167.57
 $204.11
 
 S&P 500 $100.00
 $132.31
 $150.35
 $152.47
 $170.59
 $207.74
 
 DJ Utilities $100.00
 $112.67
 $147.01
 $142.57
 $168.26
 $190.76
 
 S&P Electrics $100.00
 $113.20
 $145.82
 $138.80
 $161.20
 $180.76
 
               
201520162017201820192020
PSEG$100.00 $117.78 $143.42 $150.12 $175.77 $179.96 
S&P 500$100.00 $111.95 $136.38 $130.39 $171.44 $202.96 
DJ Utilities$100.00 $118.18 $133.95 $136.61 $173.90 $176.83 
S&P Utilities$100.00 $116.29 $130.36 $135.72 $171.48 $172.38 

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The following table indicates the high and low sale prices for our common stock and dividends paid for the periods indicated:
         
 Common Stock High Low 
Dividend
per Share
 
  
 2017       
 First Quarter $46.14
 $42.77
 $0.43
 
 Second Quarter $45.94
 $42.47
 $0.43
 
 Third Quarter $47.47
 $41.67
 $0.43
 
 Fourth Quarter $53.28
 $46.05
 $0.43
 
 2016       
 First Quarter $47.22
 $37.85
 $0.41
 
 Second Quarter $47.41
 $42.77
 $0.41
 
 Third Quarter $46.81
 $41.07
 $0.41
 
 Fourth Quarter $44.29
 $39.28
 $0.41
 
         
pseg-20201231_g4.jpg
On February 20, 2018,16, 2021, our Board of Directors approved a $0.45$0.51 per share common stock dividend for the first quarter of 2018.2021. This reflects an indicative annual dividend rate of $1.80$2.04 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.
The following table indicates our common share repurchases in the open market during the fourth quarter of 2017 to satisfy obligations under various equity compensation award grants:
       
 Three Months Ended December 31, 2017 
Total Number
of Shares
Purchased
 
Average
Price Paid
per Share
 
 October 1-October 31 —
 $—
 
 November 1-November 30 486,635
 $49.86
 
 December 1-December 31 —
 $—
 
       
In December 2017,2020, we entered into a share repurchase plan that complies with Rule 10b5-1 of the Securities Exchange Act of 1934, as amended, solely with respect to the repurchase of shares to satisfy obligations under equity compensation awards that are expected to vest or be exercisedissued in 2018.2021 and the repurchase of shares to satisfy purchases by employees under the Employee Stock Purchase Plan during 2021. There were no common share repurchases in the open market during the fourth quarter of 2020.
The following table indicates the securities authorized for issuance under equity compensation plans as of December 31, 2017:2020:
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 Plan Category 
Number of Securities
to be Issued upon
Exercise of
Outstanding Options,
Warrants and Rights
 
Weighted-Average
Exercise Price of
Outstanding
Options, Warrants
and Rights
 
Number of Securities
Remaining Available
for Future Issuance
under Equity
Compensation Plans
 
 Long-Term Incentive Plan 347,900
 $33.49
 13,771,542
 
 Employee Stock Purchase Plan —
 —
 3,174,168
 
 Total 347,900
 $33.49
 16,945,710
 
         
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— $—15,279,588 
Equity Compensation Plans Not Approved by Security Holders— — — 
Total—$—15,279,588
The number of shares available for future issuance includes amounts remaining under our Amended and Restated 2004 Long-Term Incentive Plan (LTIP), 2007 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), including accrued dividend equivalent units. 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 also increased by the number of shares that are withheld to satisfy tax withholding obligations relating to any plan awards as well as shares subject to awards that are forfeited, canceled or otherwise terminated without the issuance of shares. For additional discussion of specific plans concerning equity-based compensation, see Item 8. Financial Statements and Supplementary Data—Note 18.20. 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.
PSEG Power
We own all of PSEG Power’s outstanding limited liability company membership interests. For additional information regarding PSEG Power’s ability to pay dividends, see Item 7. MD&A—Liquidity and Capital Resources.

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ITEM 6. SELECTED FINANCIAL DATA
PSEG
The information presented below should be read in conjunction with the MD&A and the Consolidated Financial Statements and Notes to Consolidated Financial Statements (Notes).
             
 PSEG           
 Years Ended December 31, 2017 2016 2015 2014 2013 
   Millions, except Earnings per Share 
 Operating Revenues (A) $9,084
 $9,061
 $10,415
 $10,886
 $9,968
 
 Income from Continuing Operations (B)(C) $1,574
 $887
 $1,679
 $1,518
 $1,243
 
 Net Income (B)(C) $1,574
 $887
 $1,679
 $1,518
 $1,243
 
 Earnings per Share:           
 Income from Continuing Operations           
 Basic $3.12
 $1.76
 $3.32
 $3.00
 $2.46
 
 Diluted $3.10
 $1.75
 $3.30
 $2.99
 $2.45
 
 Net Income           
 Basic $3.12
 $1.76
 $3.32
 $3.00
 $2.46
 
 Diluted $3.10
 $1.75
 $3.30
 $2.99
 $2.45
 
 Dividends Declared per Share $1.72
 $1.64
 $1.56
 $1.48
 $1.44
 
 As of December 31,           
 Total Assets $42,716
 $40,070
 $37,535
 $35,287
 $32,480
 
 Long-Term Obligations (D) $12,071
 $10,897
 $8,837
 $8,218
 $7,830
 
             
(A)Operating Revenues for 2017, 2016 and 2015 includes $438 million, $410 million and $375 million, respectively, for Long Island Electric Utility Servco, LLC (Servco), a wholly owned subsidiary of PSEG LI. See Item 8. Financial Statements and Supplementary Data—Note 4. Variable Interest Entity for additional information.
(B)Income from Continuing Operations and Net Income for 2017 and 2016 includes after-tax expenses of $577 million and $396 million, respectively, related to the early retirement of Power’s Hudson and Mercer coal/gas generation plants and after-tax charges for 2017 and 2016 totaling $45 million and $92 million, respectively, related to investments in REMA’s leveraged leases and an after-tax insurance recovery for Superstorm Sandy of $102 million for 2015. See Item 8. Financial Statements and Supplementary Data—Note 3. Early Plant Retirements, Note 7. Long-Term Investments and Note 8. Financing Receivables for additional information for 2017.
(C)Income from Continuing Operations and Net Income for 2017, include the non-cash net income benefit of $745 million, primarily resulting from the remeasurement of deferred tax liabilities required due to the enactment of the Tax Act in December 2017. See Item 8. Financial Statements and Supplementary Data—See Note 20. Income Taxes for additional information for 2017.
(D)Includes capital lease obligations.
PSE&G and Power
Omitted pursuant to conditions set forth in General Instruction I of Form 10-K.SEC Release 33-10890.

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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), Public Service Electric and Gas Company (PSE&G) and PSEG Power LLC (Power)(PSEG Power). Information contained herein relating to any individual company is filed by such company on its own behalf. PSE&G and PSEG Power each make representations only as to itself and make no representations whatsoever as to any other company.
PSEG’s business consists of two reportable segments, 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 power marketing businesses and fuel supply functions through competitive energy sales in well-developed energy markets primarily in the Northeast and Mid-Atlantic United States through its principal direct wholly owned subsidiaries. In addition, PSEG Power owns and operates solar generation in various states. PSEG Power’s subsidiaries are subject to regulation by FERC, the Nuclear Regulatory Commission (NRC), the Environmental Protection Agency (EPA) and the states in which they operate.
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PSEG’s other direct wholly owned subsidiaries are: PSEG Long Island LLC (PSEG LI), which operates the Long Island Power Authority’s (LIPA) transmission and distribution (T&D) system under an Amended and Restated Operations Services Agreement (OSA); PSEG Energy Holdings L.L.C. (Energy Holdings), which primarily hasearns it revenues from its portfolio of lease investments and holds our investment in leveraged leases;offshore wind ventures; 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 20172020 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 2018 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, 2019 and December 31, 2018, 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, 2019 (2019 Annual Report) as filed with the Securities and Exchange Commission on February 26, 2020.
EXECUTIVE OVERVIEW OF 20172020 AND FUTURE OUTLOOK
2017 Overview
We are continuing our transformation into a primarily regulated electric and gas utility that is focused on meeting customer expectations and is aligned with public policy objectives promoting infrastructure investments to modernize and improve reliability and clean energy investments. Our business plan is designed to achievefocuses on achieving growth while controlling costs and managing the risks associated with regulatory changes, fluctuating commodity prices and changes in customer demand. 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. As announced in July 2020, we continue to explore strategic alternatives for PSEG Power’s non-nuclear generating fleet, which includes more than 6,750 megawatts (MW) of fossil generation located in New Jersey, Connecticut, New York and Maryland as well as the 467 MW dc Solar Source portfolio located in various states. See Item 8. Note 4. Early Plant Retirements/Asset Dispositions for additional information.
PSE&G, PSEG Power and PSEG LI continue to provide essential services during the ongoing 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. Employees who can perform their job duties remotely are doing so. Those employees who must report to a work site are wearing personal protective equipment and practicing physical distancing measures.
The ongoing coronavirus pandemic has not had a material impact on our results of operations, financial condition or cash flows for the year ended December 31, 2020. However, 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, including the duration and severity of the outbreak as well as third-party actions taken to contain its spread and mitigate its public health effects. 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 five-year period ending December 31, 2025, PSE&G expects to invest between $13 billion to $15 billion, resulting in an expected compound annual rate base growth 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 timeframes of 2023 and 2024, respectively. The range is driven by certain unapproved investment programs, including a to-be- filed extension of the Energy Strong (ES) 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). See below for a description of the CEF program.
In 2019, we commenced our BPU-approved GSMP II, an expanded, five-year program to invest $1.9 billion beginning in 2019 to replace approximately 875 miles of cast iron and unprotected steel mains in addition to other improvements to the gas system. Approximately $1.6 billion will be recovered through periodic rate roll-ins, with the remaining $300 million to be recovered through a future base rate proceeding. As part of the settlement approved by the BPU, PSE&G agreed to file for a
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base rate proceeding no later than December 2023, to maintain a base level of gas distribution capital expenditures of $155 million per year and to achieve certain leakage reduction targets. As of December 31, 2020, we had installed 528 miles of cast iron and unprotected steel mains at an investment of $800 million.
Also in 2019, the BPU approved our ES II Program, an $842 million program to harden, modernize and improve the resiliency of our electric and gas distribution systems. This program began in the fourth quarter of 2019 and is expected to be completed by the end of 2023. Approximately $692 million of the program will be recovered through periodic rate recovery filings, with the balance to be recovered in our next distribution base rate case. As of December 31, 2020, we had invested $156 million.
In January 2020, New Jersey released its Energy Master Plan (EMP) which, among other things, recognizes the importance of the State’s EE targets and supported EVs, ES, and advanced metering infrastructure (AMI).
In September 2020, PSE&G reached a settlement with all 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, a mechanism that will provide for recovery of lost electric and gas variable margin revenues relative to a baseline of the test year in our last base rate case from July 2017 to June 2018. The deferral period for this mechanism is effective in June 2021 for electric and October 2021 for gas. PSE&G will suspend its gas Weather Normalization Charge (WNC) when the gas deferral period begins.
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 includes implementation of AMI, is estimated to be approximately $700 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 $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.
All of the capital costs and expenses of the CEF-EC and CEF-EV programs will be recovered in PSE&G’s next base rate case, expected in the second half of 2024. From the start of the program until the commencement of new base rates, the return on and of the capital portion of 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 in those rates. The remaining component of our CEF-EV proposal, the vehicle innovation subprogram, as well as the overall CEF-ES program, are 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, grid security and safety, (ii) address an aging transmission infrastructure, (iii) leverage technology to improve the operation of the system, (iv) reduce transmission constraints, (v) meet growing demand and (vi) meet environmental requirements and standards set by various regulatory bodies. Our planned capital spending for transmission in 2021-2023 is $2.5 billion.
As noted above, PSE&G has been deemed by New Jersey to provide essential services during the ongoing coronavirus pandemic. Our capital programs, including GSMP II, ES II and our transmission infrastructure investments, have not been materially impacted to date. However, a prolonged outbreak and the associated economic impacts, which could extend beyond the duration of the pandemic, could impact our ability to obtain necessary permits and approvals and could lead to shortages of necessary materials, supplies and labor. In addition, a determination by any state or federal regulatory authority that one or all of our projects is non-essential could require us to temporarily halt work. Any delay in our planned capital program could impact our operational performance and could materially impact our results of operations and financial condition through decreased cost recovery.
Further, the ongoing coronavirus pandemic has led many state and federal agencies to implement remote working protocols and divert resources to address the pandemic which, if prolonged, could impact regulatory agencies’ ability to review proposed programs and delay the timing of approvals for matters subject to regulatory approval, including the approval of various clause recovery mechanisms.
PSE&G has experienced a reduction in demand from its commercial and industrial (C&I) customers, partially offset by increases in residential demand, and adverse changes to residential and C&I payment patterns. PSE&G expects these changes to continue during the prolonged coronavirus pandemic. In October 2020, the state formally extended its moratorium on non-safety related service disconnections for non-payment for residential customers through March 15, 2021. 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 could extend beyond the duration of the coronavirus pandemic.PSE&G’s electric distribution bad debt expense is recoverable through its Societal Benefits Clause (SBC) mechanism. PSE&G
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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.
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 the prudently incurred incremental costs related to COVID-19 beginning on March 9, 2020 through September 30, 2021, or 60 days after the New Jersey governor determines that the Public Health Emergency is no longer in effect, or in the absence of such a determination, 60 days from the time the Public Health Emergency automatically terminates by law, whichever is later. Deferred costs are to be offset by any federal or state assistance that the utility may receive as a direct result of the COVID-19 pandemic. During 2020, PSE&G recorded a Regulatory Asset related to COVID-19 to defer incremental costs of $51 million, which PSE&G believes are recoverable under the BPU order.
While the impact on our results of operations, financial condition and cash flows for the year ended December 31, 2020 has not been material, a prolonged coronavirus pandemic and the associated economic impacts, which could extend beyond the duration of the pandemic, could materially impact cash from operations, Accounts Receivable and bad debt expense.
PSEG Power
In July 2020, we announced that we are exploring strategic alternatives for PSEG Power’s non-nuclear generating fleet with the intention of accelerating the transformation of our business into a primarily regulated electric and gas utility, with a contracted generation business. It is expected to reduce overall business risk and earnings volatility, improve PSEG’s credit profile and is consistent with PSEG’s climate strategy and sustainability efforts, which is to focus on clean energy investments, methane reduction, and zero-carbon generation. PSEG intends to retain ownership of PSEG Power’s existing nuclear fleet. Since the announcement, we have engaged in proprietary activities relating to the potential divestiture of, and begun the marketing processes for these assets and any potential transactions are expected to be completed sometime in 2021. There is no assurance that the strategic review will result in a sale or other disposition of all or any portion of these assets on terms that are favorable to us, or at all. Any transaction would be subject to market conditions and customary closing conditions, including the receipt of all required regulatory approvals.
At PSEG Power, 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 2020, our natural gas and nuclear units generated 22.1 and 30.8 terawatt hours and operated at a capacity factor of 48.3% and 90.3%, respectively. Our commitments for load, such as basic generation service (BGS) in New Jersey and other bilateral supply contracts, are backed by this generation or may be combined with the use of physical commodity purchases and financial instruments from the market to optimize the economic efficiency of serving our obligations. PSEG Power’s hedging practices help to manage some of the volatility of the merchant power business. More than 70% of PSEG Power’s expected gross margin in 2021 relates to hedging of our energy margin, our expected revenues from the capacity market mechanisms, Zero Emission Certificate (ZEC) revenues and certain ancillary service payments such as reactive power.
As discussed further below under “Wholesale Power Market Design,” FERC issued an order establishing new rules for PJM’s capacity market, extending the PJM Minimum Offer Price Rule (MOPR) to include both new and existing resources that receive or are entitled to receive certain out-of-market payments, with certain exemptions. PSEG Power’s New Jersey nuclear plants that receive ZEC payments will be subject to the new MOPR. In addition, as a result of FERC’s finding that default procurement auctions such as BGS could be considered subsidies, it is possible that other PSEG units could be subject to the MOPR. The MOPR’s floor prices are not expected to prevent either our nuclear or gas-fired units from clearing in the next Reliability Pricing Model (RPM) auction. We cannot predict whether additional changes will be made to the MOPR, or whether changes will occur in the PJM market that would impact our ability to clear any of these units in future RPM auctions.
During 2020, as a result of the ongoing coronavirus pandemic, PSEG Power experienced a decrease in aggregate wholesale electric demand. An extended outbreak could have a material adverse impact on future results of operations and cash flows.
PSEG Power has also implemented protocols to ensure the safety and health of employees at its generation facilities and contractors working at the facilities during planned outages. A prolonged unavailability of employees and contractors due to the ongoing coronavirus pandemic could materially and adversely impact our ability to operate our generation facilities, which would have a material impact on our business, results of operations and cash flows.
PSEG LI
Following the effects of Tropical Storm Isaias, the New York Attorney General 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 state electric service providers, including PSEG LI, and other state telephone, cable and internet providers into their preparation and restoration efforts following Tropical Storm Isaias.Although the inquiry by the New York Attorney General remains pending, the DPS issued an interim storm investigation report. With respect to PSEG LI, the DPS’ report found that PSEG LI violated its Emergency Response Plan and DPS Regulations, and recommended that LIPA
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consider taking various actions, including terminating or renegotiating the OSA. LIPA also initiated its own review of PSEG LI’s performance and issued a report with recommendations for improvements to PSEG LI’s structure and processes, including a timeline for implementing those recommendations. That report also recommended that LIPA either renegotiate or terminate the OSA.
PSEG LI agreed with LIPA that it would fund approximately $6.5 million in claims by customers for food and medication spoilage costs incurred as a result of being without electric service during the storm.
In December 2020, LIPA filed a complaint against PSEG LI in New York State court alleging multiple breaches of the OSA in connection with PSEG LI’s preparation for and response to Tropical Storm Isaias seeking specific performance and $70 million in damages. Pursuant to recommendations by the New York State Department of Public Service, LIPA has initiated a series of actions to allow its board to determine whether to seek to terminate the OSA or instead continue with PSEG LI as its Service Provider.
PSEG LI is fully cooperating with the inquiries by the New York Attorney General and the DPS, and we cannot predict their outcome. PSEG LI also continues to work closely with LIPA to address the recommendations in LIPA’s report. PSEG LI intends to vigorously defend itself with regard to the allegations in LIPA’s complaint alleging breaches of the OSA; however 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 power. Building on this mission, we believe in a future where customers universally use less energy, the energy they use is cleaner, and its delivery is more reliable and more resilient. In July 2019, we announced that we expect to cut carbon emissions at PSEG Power’s generation fleet by 80% by 2046, from 2005 levels. We have also announced our vision of attaining net zero- carbon emissions by 2050, assuming advances in technology, public policy and customer behavior.
PSE&G has also undertaken a number of initiatives that support the reduction of greenhouse gas (GHG) emissions and the implementation of energy efficiency initiatives. The first phase of our GSMP replaced approximately 450 miles of cast-iron and unprotected steel gas 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 gas leaks in our distribution system, which would reduce the release of methane, a potent GHG, into the air. In addition, PSE&G’s CEF-EE which was approved by the BPU in September 2020 and the CEF-EC and CEF-EV programs, which were approved by the BPU in January 2021 and the proposed CEF-ES program are intended to support New Jersey’s EMP through programs designed to help customers increase their energy efficiency, support the expansion of the electric vehicle 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.
Offshore Wind
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. 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 could provide first power in late 2024. Completion of the acquisition is anticipated to occur in the first half of 2021, subject to approval by the BPU and other customary closing conditions. 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.
Operational Excellence
We emphasize operational performance while developing opportunities in both our competitive and regulated businesses. In 2020, our utility continued its efforts to control costs while maintaining strong operational performance and has implemented protocols to ensure that we are providing essential services to our customers during the ongoing coronavirus pandemic in a safe and reliable manner. Flexibility in our generating fleet has allowed us to take advantage of opportunities in a rapidly evolving market as we remain diligent in managing costs.
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 2020 as we
•maintained sufficient liquidity,
•maintained solid investment grade credit ratings, and
•increased our annual dividend for 2020 to $1.96 per share.
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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 potential sale of our non-nuclear generation fleet are expected to help support our business and financial profile.
Financial Results
The financial results for PSEG, PSE&G and PSEG Power for the years ended December 31, 2020 and 2019 are presented as follows:
 Years Ended December 31,
20202019
Millions, except per share data
 PSE&G$1,327 $1,250 
PSEG Power594 468 
Other(16)(25)
PSEG Net Income$1,905 $1,693 
PSEG Net Income Per Share (Diluted)$3.76 $3.33 
Our 2020 over 2019 increase in Net Income was due primarily to higher earnings from a gain on the sale of PSEG Power’s ownership interest in a generating facility in 2020 and a loss on its ownership interests in two fossil plants in 2019, T&D investments at PSE&G and pension and OPEB credits. These increases were partially offset at PSEG Power by mark-to-market (MTM) losses in 2020 as compared to gains in the prior year. In addition. higher earnings were reduced by lower energy market prices on lower volumes of electricity sold in PJM and lower capacity revenues which were somewhat tempered by higher ZEC revenues and lower fuel costs at PSEG Power. 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 when combined with the cash flow generated by PSEG Power, 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, including:initiatives.
Disciplined Investment
improving utility operations through growth inWe utilize rigorous criteria and consider a number of external factors, focusing on the value for our stakeholders, as well as other impacts, such as the economic impact of the ongoing coronavirus pandemic, when determining how and when to efficiently deploy capital. We principally explore opportunities for investment in T&Dareas that complement our existing business and other infrastructure projects designed to enhance system reliabilityprovide reasonable risk-adjusted returns and resiliencycontinuously assess and to meet customer expectations and public policy objectives, and
maintaining and expanding a reliable generation fleet with the flexibility to utilize a diverse mix of fuels which allows us to respond to market volatility and capitalize on opportunities as they arise.


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Financial Results
The results for PSEG, PSE&G and Power for the years ended December 31, 2017 and 2016 are presented below:
       
   Years Ended December 31, 
   2017 2016 
 Earnings (Losses) Millions, except per share data 
 PSE&G $973
 $889
 
 Power 479
 18
 
 Other 122
 (20) 
 PSEG Net Income $1,574
 $887
 
       
 PSEG Net Income Per Share (Diluted) $3.10
 $1.75
 
       
Our 2017 over 2016 increase in Net Income was due primarily to the favorable impacts of new tax legislation at Power and Energy Holdings in 2017, discussed below, partially offset by higher charges in 2017 related to the early retirement of our Hudson and Mercer units. Higher transmission revenues in 2017 at PSE&G, lower charges in 2017 related to investments in certain leveraged leases at Energy Holdings and lower plant outage costs at Power, partially offset by lower volumes of electricity sold at lower average prices, also contributed to the increase in Net Income. For a more detailed discussion of our financial results, see Results of Operations.
During 2017, we maintained a strong balance sheet. We continued to effectively deploy capital without the need for additional equity, while our solid credit ratings aided our ability to access capital and credit markets. The greater emphasis on capital spending for projects on which we receive contemporaneous returns at PSE&G, our regulated utility, in recent years has yielded strong results, which when combined with the cash flow generated by Power, our merchant generator and power marketer, has allowed us to increase our dividend. These actions to transition our business to meet market conditions and investor expectations reflect our multi-year, long-term approach to managing our company. Our focus has been to invest capital in T&D and other infrastructure projects aimed at maintaining service reliability to our customers and bolstering our system resiliency. At Power, we strive to improve performance and reduce costs in order to enhance the value of our generation fleet in light of low gas prices, environmental considerations and competitive market forces that reward efficiency and reliability.
At PSE&G, we continue to invest in transmission projects that focus on reliability improvements and replacement of aging infrastructure. We also continue to make investments to improve the resiliency of our gas and electric distribution system as part of our Energy Strong program that was approved by the BPU in 2014 and to seek recovery on such investments. We are modernizing PSE&G’s gas distribution systems as part of our Gas System Modernization Program (GSMP) that was approved by the BPU in late 2015. In July 2017, we filed a petition with the BPU for a GSMP II program, an extension of GSMP to continue to modernize our gas system, through which PSE&G has proposed investing $2.7 billion over five years beginning in 2019. This matter is pending. We believe the petition is consistent with the Infrastructure Investment Program (IIP) regulations that the BPU approved in December 2017. In August 2017, the BPU approved PSE&G’s petition for an Energy Efficiency 2017 Program (EE 2017) to extend three existing energy efficiency subprograms (multi-family, direct install and hospital efficiency) and establish two new residential energy efficiency offerings. The EE 2017 allows for $69 million of additional investment and $16 million of additional administrative and information technology costs. The EE 2017 was added as the eleventh component of the Green Program Recovery Charges (GPRC) rate effective September 1, 2017. Over the past few years, these types of investments have alteredoptimize our business mix as appropriate. In 2020, we
•made additional investments in T&D infrastructure projects on time and on budget,
•continued to reflectexecute our Energy Efficiency and other existing BPU-approved utility programs,
•exercised our option to acquire a higher percentage25% equity interest in the Ocean Wind offshore wind project in New Jersey while continuing to evaluate potential additional offshore wind opportunities, and
•launched a process to evaluate the potential sale of earnings contribution by PSE&G.
In January 2018, PSE&G filedPSEG Power’s non-nuclear generation business which is expected to improve our business profile and accelerate our transition to a distribution base rate case as required by the BPU as a condition of approval of its Energy Strong Program. The filing requests an approximate one percent increase in revenues and seeks to recover investments made to strengthenmore regulated electric and gas distribution systems. In its filing, PSE&G requested that these rates take into accountutility, with a reduction in the revenue requirement as a result of the federal corporate income tax rate reduction from 35% to 21% provided in new tax legislation enacted in December 2017 (Tax Act), including a one-time credit for estimated excess income taxes collected between January 1, 2018 and the time new rates go into effect, and the flow-back to customers of certain additional tax benefits. PSE&G anticipates the new base rates will take effect in the fourth quarter of 2018.
Separately, in January 2018, the BPU issued an order commencing a proceeding to ensure that the rate revenue resulting from expenses relating to taxes reflected in rates but no longer owed as the result of the Tax Act shall be passed onto the ratepayers. The BPU directed New Jersey utilities (including PSE&G) to make filings by March 2, 2018 setting forth interim rates to be effective April 1, 2018, reflecting the new federal corporate tax rate, and to subsequently file proposed final rates, effective July 1, 2018, incorporating all other effects of the Tax Act. This proceeding is currently pending.

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As a result of the enactment of the Tax Act, various state regulatory authorities, including the BPU, have taken action to ensure that excess federal income taxes previously collected in rates are returned to ratepayers. We have made filings to adjust the revenue requirement in certain of our rate matters as a result of the change in federal income tax rate. We continue to assess whether any further action needs to be taken by the company at this time.
For additional information on our specific filings, see Item 8. Financial Statements and Supplementary Data—Note 6. Regulatory Assets and Liabilities.
Power manages its existing firm pipeline transportation contracts for the benefit of PSE&G’s customers through the basic gas supply service (BGSS) arrangement. The contracts are sized to provide for delivery of a reliable gas supply to PSE&G customers on peak winter days. When pipeline capacity beyond the customers’ needs is available, Power may use it to make third-party sales and supply gas to its generating units in New Jersey. Alternatively, gas supply and pipeline capacity constraints could adversely impact our ability to meet the needs of our utility customers and generating units. Power’s hedging practices and ability to capitalize on market opportunities help it to balance some of the volatility of the merchant powercontracted energy business. More than half of Power’s expected gross margin in 2018 relates to our hedging strategy, our expected revenues from the capacity market mechanisms and certain ancillary service payments such as reactive power.
Our investments in Keys Energy Center (Keys), Sewaren 7 and Bridgeport Harbor Station 5 (BH5) reflect our recognition of the value of opportunistic growth in the Power business. See Item 1. Business—Power for additional information on major growth projects. These additions to our fleet both expand our geographic diversity and adjust our fuel mix and are expected to contribute to the overall efficiency of operations.
Since 2013, several nuclear generating stations in the United States have closed or announced early retirement due to economic reasons, or have announced being at risk for early retirement. Most recently, in February 2018, Exelon, a co-owner of the Salem units, announced its intention to accelerate the closure of its Oyster Creek nuclear plant located in New Jersey, one year earlier than previously planned for economic reasons. These closures and retirements are generally due to the decline in market prices of energy, resulting from low natural gas prices driven by the growth of shale gas production since 2007, the continuing cost of regulatory compliance and enhanced security for nuclear facilities, both federal and state-level policies that provide financial incentives to construct renewable energy such as wind and solar and the failure to adequately compensate nuclear generating stations for the attributes they bring similar to renewable energy production. These trends have significantly reduced the revenues of nuclear generating stations while limiting their ability to reduce the unit cost of production. This may result in the electric generation industry experiencing a further shift from nuclear generation to natural gas-fired generation, creating less diversity of the generation fleet.
If any or all of the Salem and Hope Creek units were shut down, it would significantly alter New Jersey’s energy supply predominately by increasing New Jersey’s reliance on natural gas generation. Such a decrease in fuel diversity could also increase the market’s vulnerability to price fluctuations and power disruptions in times of high demand. The New Jersey Legislature is assessing legislation that would provide a safety net in order to prevent the loss of environmental attributes from nuclear generating stations. We cannot predict whether the legislation will be enacted or, if enacted, whether our nuclear generating stations in New Jersey will be selected or whether the legislation will provide a sufficient safety net for the continued operation of nuclear generating stations in New Jersey.
In the ordinary course, management, and in the case of the Salem units the co-owner, each makes a number of decisions that impact the operation of our nuclear units beyond the current year, including whether and to what extent these units participate in RPM capacity auctions, commitments relating to refueling outages and significant capital expenditures, and decisions regarding our hedging arrangements. When considering whether to make these future commitments, management’s decisions will primarily be influenced by the financial outlook of the units, including the progress, timing and continued outlook for enactment of proposed legislation in the state of New Jersey.
If market prices continue to be depressed and legislation is not enacted that adequately compensates nuclear generating stations for their attributes, Power anticipates it will no longer be covering its costs nor be adequately compensated for its market and operational risks at the Salem and Hope Creek nuclear units and would anticipate retiring these units early. The costs associated with any such retirement, which may include, among other things, accelerated depreciation and amortization or impairment charges, accelerated asset retirement costs, severance costs, environmental remediation costs and additional funding of the Nuclear Decommissioning Trust Fund (NDT) would be material to both PSEG and Power.
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 Return on Equity (ROE)
In May 2020, FERC issued an order revising an earlier order that established a new ROE policy for reviewing existing transmission ROEs. The revised methodology uses the Discounted Cash Flow model, the Capital Asset Pricing model and the risk premium model to determine if an existing base ROE is unjust and unreasonable and, if so, what replacement ROE is
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appropriate. FERC’s order indicated that it would not be bound by this revised methodology when considering the just and reasonableness of a utility’s ROE in future proceedings. We continue to analyze the potential impact of these methodologies.
Transmission Planning
There are several mattersROE complaints have been pending before FERC regarding MISO transmission owners, the ISO New England Inc. transmission owners and the U. S. Court of Appeals for the District of Columbia Circuit that concern the allocation of costs associated with transmission projects being constructed by PSE&G. Regardless of how these proceedings are resolved, PSE&G’s ability to recover the costs of these projects will not be affected. However, the result of these proceedings could ultimately impact the amount of costs borne by ratepayersutilities in New Jersey.other jurisdictions. In addition, as a basic generation service (BGS) supplier, Power provides servicesover the past few years, several companies have negotiated settlements that include specified transmission costs. If the allocation of the costs associated with the transmission projects were to increase these BGS-related transmission costs, BGS suppliers may be entitled to recovery, subject to BPU approval. We do not believe that these matters will have a material effect on Power’s business or results of operations.
Several complaints have been filed and several remain pending at FERC against transmission owners around the country, challenging those transmission owners’ base return on equity (ROE). Certain of those complaints have resulted in decisions and others have been settled, resultingreduced ROEs.
We are engaged in reductions of those transmission owners’ base ROEs. The results of these other proceedings could set precedents for other transmission ownerssettlement discussions with formula rates in place, including PSE&G.
Wholesale Power Market Design
Capacity market design, including the Reliability Pricing Model (RPM) in PJM, remains an important focus for us. During 2015, PJM implemented a new “Capacity Performance” (CP) mechanism that created a more robust capacity product with enhanced incentives for performance during emergency conditions and significant penalties for non-performance. The CP product was implemented fully in the May 2017 RPM auction for the 2020-2021 Delivery Year. Subsequent to its implementation, FERC approved changes to the CP construct that will enhance the participation of intermittent and demand response resources (seasonal resources). However, two complaints remain pending that ask FERC to investigate the rules governing the participation of seasonal resources and extend the participation of the base resources for future auctions.
In May 2017, PJM announced the results of the RPM capacity auction for the 2020-2021 Delivery Year. Power cleared approximately 7,800 MW of its generating capacity at an average price of $174 per MW-day for the 2020-2021 delivery period. In the two prior capacity auctions covering the 2019-2020 and 2018-2019 delivery years, Power cleared approximately 8,900 MW at an average price of $116 per MW-day and approximately 8,700 MW at an average price of $215 per MW-day, respectively. Prices in the most recent auction reflect PJM’s downwardly-revised demand forecast, changes in the emergency transfer limits due to transmission expansionBPU Staff and the effectsNew Jersey Division of bothRate Counsel about the new generationlevel of PSE&G’s base transmission ROE and uncleared generation from the prior year’s auction.
As a result of the efforts of certain entitiesother formula rate matters. An adverse change to PSE&G’s base transmission ROE or ROE incentives could be material. We estimate that for each 25 basis point reduction in PJM to obtain financial support arrangements from their state commissions, a group of suppliers requested that FERC direct PJM to expand the currently effective “minimum offer price rule” to apply to certain existing units seeking subsidies. The suppliers’ request was intended to avoid a scenario where the subsidized generatorsPSE&G’s base transmission ROE, and all other factors unchanged, PSE&G’s annual Net Income and annual cash inflows would submit bids into the PJM capacity market that did not reflect their actual costs of operation and could artificially suppress capacity market prices. We are currently awaiting FERC action on the suppliers’ request anddecrease by approximately $15 million. While we cannot predict the outcome of the proceeding.settlement discussions, it may result in a change to our base transmission ROE that is multiples of this sensitivity measure.
Wholesale Power Market Design
In June 2017, PJMDecember 2019, FERC issued an energyorder establishing new rules for PJM’s capacity market, extending the PJM MOPR to include both new and existing resources that receive or are entitled to receive certain out-of-market payments, with certain exemptions.
PSEG Power’s New Jersey nuclear plants that receive ZEC payments will be subject to the new MOPR. Resources that are subject to the MOPR continue to have the ability to justify a bid below the MOPR floor price formation proposalunder the unit-specific exemption. The MOPR floor prices are not expected to address a flawprevent either our nuclear units or gas-fired units from clearing in the next RPM auction. In May 2020, FERC issued an order modifying PJM’s methodology for pricing energy marketreserves. It also directed PJM to use forward-looking energy and ancillary service revenues,which can affect how the MOPR offer floors are calculated. In addition, if one or more electric distribution zones in which energy prices during off-peak periods often do not reflectNew Jersey (or another state) were to become fixed resource requirement (FRR) alternativeservice areas, procurements needed for that area could provide an alternate means for nuclear units whose ability to clear in RPM auctions was affected by the production costs of generators during these periods even though they are serving load. PJM’s proposal would allow large, inflexible unitsMOPR to set price. If placed into effect, this proposal will improve price formation by ensuring that the marginal costs of units serving loadprovide capacity within PJM. We cannot predict whether additional changes will be better reflectedmade to the MOPR, or whether changes will occur in clearing prices.the PJM market that would impact our ability to clear any of these units in future RPM auctions.
States that have clean energy programs designed to achieve public policy goals that support such resources as solar, offshore wind and nuclear, are not prevented from pursuing those programs by the expanded MOPR and could choose to utilize the existing FRR approach authorized under the PJM tariff. Subsidized units that cannot clear in a RPM capacity auction because of the expanded MOPR could still count as capacity resources to a load serving entity using the FRR approach. In a March 2020 order, the BPU initiated an investigation to examine whether New Jersey can achieve its long-term clean energy and environmental objectives under the current resource adequacy procurement paradigm and potential alternatives. One of the areas of inquiry concerns the potential creation of FRR service areas within New Jersey. We cannot predict the outcomeimpact these rules or any measures taken by the BPU will have 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 CO2 emissions will be required to procure credits for each ton they emit. In response to RGGI, PJM initiated a process in 2019 to investigate the development of this matter.
See Item 1. Business—Federal Regulation for additional information.
Distribution
The BPU has enacted IIP regulationsa carbon pricing mechanism that allow utilitiesmay mitigate the environmental and financial distortions that could occur when emissions “leak” from non-participating states to construct, install, or remediate utility plant and facilities relatedthe RGGI states. If the process leads to reliability, resiliency, and/or safety to supporta market solution, it could have a material impact on the provisionvalue of safe and adequate service. Under these regulations, utilities can seek authority to make specified infrastructure investments in programs extending for up to five years with accelerated cost recovery mechanisms. The BPU characterized the IIP regulations as a regulatory initiative intended to create a financial incentive for utilities to accelerate the level of investment needed to promote the timely rehabilitation and replacement of certain non-revenue producing infrastructure that enhances reliability, resiliency, and/or safety. PSEG Power’s generating fleet.
Environmental Regulation
We continue to advocate for the development and implementation of fair and reasonable rules by the EPA and state environmental regulators. In particular, section 316(b) of the Federal Water Pollution Control Act requires that cooling water intake structures, which are a significant part of the generation of electricity at steam-electric generating stations, reflect the

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best technology available for minimizing adverse environmental impacts. Implementation of Section 316(b) and related state regulations could adversely impact future nuclear and fossil operations and costs.
In March 2017, the President of the United States issued an Executive Order that instructed the EPA to review the New Source Performance Standards that establish emissions standards for CO2 for certain new fossil power plants, and the Clean Power Plan (CPP), a greenhouse gas emissions regulation under the Clean Air Act for existing power plants that establishes state-specific emission rate targets based on implementation of the best system of emission reduction. In October 2017, the EPA Administrator signed a proposed repeal of the CPP. The EPA Administrator concluded that the CPP exceeds the EPA’s statutory authority by considering measures that are beyond the control of the owners of the affected sources (fossil fuel-fired electric generating units). The EPA is considering rulemaking to replace the CPP. PSEG cannot assess the impact of any such rulemaking on its business and future results of operations at this time.
We are subject to liability under environmental laws for the costs of remediating environmental contamination of property now or formerly owned by us and of property contaminated by hazardous substances that we generated. In particular, the historic operations of PSEG companies and the operations of numerous other companies along the Passaic and Hackensack Rivers are alleged by Federal and State agencies to have discharged substantial contamination into the Passaic River/Newark Bay Complex in violation of variousstatutes. 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 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. Financial Statements and Supplementary Data—Note 13.15. Commitments and Contingent Liabilities.Liabilities.
FERC ComplianceNuclear
Since September 2014, FERC StaffIn 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
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hour generated in payments to selected nuclear plants (ZEC payment)). These nuclear plants are expected to receive ZEC revenue for approximately three years, through May 2022, and will be obligated to maintain operations during that period, subject to 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. The ZEC payment may be adjusted by the BPU (a) at any time to offset environmental or fuel diversity payments that a selected nuclear plant may receive from another source or (b) at certain times specified in the ZEC legislation if the BPU determines that the purposes of the ZEC legislation can be achieved through a reduced charge that will nonetheless be sufficient to achieve the State’s air quality and other environmental objectives by preventing the retirement of nuclear plants. For instance, the New Jersey Division of Rate Counsel (New Jersey Rate Counsel), in written comments filed with the BPU, has advocated for the BPU to offset market benefits resulting from New Jersey’s rejoining the 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.
The BPU’s decision awarding ZECs has been conducting a preliminary non-public investigation regarding errors inappealed by the calculation of certain components of Power’s cost-based bids for its New Jersey fossil generating unitsRate Counsel. PSEG cannot predict the outcome of this matter.
In October 2020, PSEG Power filed with the BPU its ZEC applications for Salem 1, Salem 2 and Hope Creek for the three-year eligibility period starting in the PJM energy market and the quantityJune 2022. No other plants applied for ZECs for this eligibility period. PSEG Power is not aware of energy that Power offered into the energy marketany changes from its ZEC application for its fossil peaking units compared to the amounts for which Power was compensated in the capacity market for those units. While considerable uncertainty remains as to the final resolution of these matters, based upon developments in the investigation in the first quarter of 2017, Power believes the disgorgement and interest costs relatedeligibility period that would materially affect its ability to the cost-based bidding matter may range between approximately $35 million and $135 million, depending on the legal interpretation of the principles under the PJM Tariff, plus penalties. Since no point within this range is more likely than any other, Power has accrued the low end of this range of $35 million by recording an additional pre-tax chargeestablish eligibility to income of $10 millionbe awarded ZECs during the three months ended March 31, 2017. PSEGsecond eligibility period. A final BPU decision is unable to reasonably estimate the range of possible loss, if any, for the quantity of energy offered matter or the penalties that FERC would impose relating to either the cost-based bidding or quantity of energy matter. However, any of these amounts could be individually material to PSEG and Power.expected in April 2021. We cannot predict the final outcome of these matters. For additional information, see Item 8. Financial Statementsthis matter.
In the event that (i) the ZEC program is overturned or is otherwise materially adversely modified through legal process; (ii) the amount of ZEC payments that may be awarded or other terms and Supplementary Data—Note 13. Commitments and Contingent Liabilities.
Early Retirement of Hudson and Mercer Units
On June 1, 2017, Power completed its previously announced retirementconditions of the generationsecond ZEC eligibility period proposed by the BPU in its final decision differ from those of the current ZEC period; or (iii) any of the Salem 1, Salem 2 and Hope Creek plants is not awarded ZEC payments by the BPU and does not otherwise experience a material financial change, PSEG Power will take all necessary steps to cease to operate all of these plants. Alternatively, if all of the Salem 1, Salem 2 and Hope Creek plants are selected to continue to receive ZEC payments but 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 the existing coal/gas units at the Hudson and Mercer generating stations. The decision to retire the Hudson and Mercer units had a material effect on PSEG’s and Power’s results of operationsthese plants would result in 2016 and continued to adversely impact their results of operations in 2017. As of June 1, 2017, Power completed recognition of the incremental Depreciation and Amortization (D&A) of $938 million ($964 million in total) due to the significant shortening of the expected economic useful lives of Hudson and Mercer. During 2017, Energy Costs of $15 million and Operation and Maintenance (O&M) of $23 million were also incurred. See Item 8. Financial Statements and Supplementary Data—Note 3. Early Plant Retirements for additional information.
Power is exploring various opportunities with these sites, including using the sites for alternative industrial activity or the disposition of one or both of the sites. If Power determines not to use the sites for alternative industrial activity, the early retirement of the units at such sites would trigger obligations under certain environmental regulations, including possible remediation. The amounts for any such remediation are neither currently probable nor estimable but may be material.
In addition, PSEG and Power continue to monitor their other coal assets, including the Keystone and Conemaugh generating stations, to assess their economic viability through the end of their designated useful lives and their continued classification as held for use. The precise timing of a change in useful lives may be dependent upon events out of PSEG’s and Power’s control and may impact their ability to operate or maintain certain assets in the future. These generating stations may be impacted by factors such as environmental legislation, co-owner capital requirements and continued depressed wholesale power prices or capacity factors, among other things. Any early retirement or change in the classification as held for use of our remaining coal units may have a material adverse impact on PSEG’s and PSEG Power’s future financial results.results of operations.

Nuclear Refueling Outage
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Leveraged Lease Impairments
GenOn Energy, Inc. (GenOn)The Salem 1 nuclear generating plant completed its scheduled refueling outage in mid-December 2020. During this outage, the plant’s main generator stator replacement was completed successfully. Additionally, all reactor vessel inspections and certain of its subsidiaries filed voluntary petitions for relief under Chapter 11 of the United States Bankruptcy Code on June 14, 2017. NRG REMA, LLC (REMA) was not included in the GenOn bankruptcy filing. GenOn is currently engaged in a balance sheet restructuring, which will take an undetermined time to complete. PSEG cannot predict the outcome of GenOn’s efforts to restructure its balance sheet and improve its liquidity.
During the first quarter of 2017, due to continuing liquidity issues facing REMA, economic challenges facing coal generation in PJM, and based upon an ongoing review of available alternativesupgrades were also completed as well as discussions with REMA management, Energy Holdings recorded an additional $55 million pre-tax charge for its current best estimate of loss relating to its REMA leveraged lease receivables, which was reflected in Operating Revenues. During the second quarter of 2017, Energy Holdings recorded an additional $22 million pre-tax charge for its current best estimate of loss related to lease receivables due to collectability of payments ($15 million) and economics impacting the residual value ($7 million) of certain leased assets. PSEG continues to monitor any changes to REMA’s and GenOn’s status and potential impacts on Energy Holdings’ lease investments, which could include further write-downs of the values of Energy Holdings’ leveraged lease receivables, and continue to discuss the situation with various parties relevant to this matter. For additional information, see Item 8. Financial Statements and Supplementary Data—Note 7. Long-Term Investments and Note 8. Financing Receivables. There can be no assurance that a continuation or worsening of the adverse economic conditions would not lead to additional write-downs at any of our other generation units in our leveraged lease portfolio, and such write-downs could be material.
Additional facilities in our leveraged lease portfolio include the Joliet and Powerton generating facilities. Similar to Shawville, Joliet was recently converted to use natural gas. Converted natural gas units such as Shawville and Joliet may have higher operating costs and fuel consumption as well as longer start-up times compared to newer combined cycle gas units. Powerton is a coal-fired generating facility in Illinois. Each of these three facilities may not be as economically competitive as newer combined cycle gas units and could continue to be adversely impacted by the same economic conditions experienced by other less efficient natural gas and coal generation facilities, which could require Energy Holdings to write down the residual value of the leveraged lease receivables associated with these facilities.planned.
Tax Legislation
The Consolidated Appropriations Act, 2021(CAA) was enacted in late December 2020. Our initial analysis of the CAA indicates that this legislation will not have a material impact on the financial condition and cash flows of PSEG, PSE&G and PSEG Power. On December 31, 2020, Notice 2021-05 was issued. For qualifying offshore wind or Federal Land projects, the notice extends the four year continuity safe harbor to no more than ten calendar years after the calendar year during which construction of the project began. We are still in the process of analyzing the CAA.
In December 2017,July 2020, the U.S. government enacted comprehensive tax legislationInternal Revenue Service (IRS) issued final and proposed regulations addressing the limitation on deductible business interest expense contained in the Tax Cuts and Jobs Act (Tax Act), which, among other things, decreased. These regulations retroactively allow depreciation to be added back in computing the statutory U.S. corporate30% adjusted taxable income tax rate from a maximum(ATI) cap, increasing the amount of 35%interest that can be deducted by unregulated businesses in years before 2022. For 2022 and after, the regulations continue to 21%, effective January 1,disallow the addback of depreciation in the computation of ATI, effectively lowering the cap on the amount of deductible business interest. The portion of PSEG’s and PSEG Power’s business interest expense that was disallowed in 2018 and made certain changes to bonus depreciation rules.2019 will now be deductible in those respective years.
AsIn March 2020, the federal Coronavirus Aid, Relief, and Economic Security Act (CARES Act) was enacted. The CARES Act allows a resultfive-year carryback of the enacted reductionany net operating loss (NOL) generated in the statutory U.S. corporate income tax rate, as well as other aspects of the Tax Act, we have recorded a one-time, non-cash earnings benefit of $745 million, including $588 million related to Power and $147 million related to Energy Holdings. This benefit is primarily due to the remeasurement of deferred tax balances. In addition, PSE&G had excess deferred taxes of approximately $2.1 billion as oftaxable year beginning after December 31, 2017 and recorded an approximate $2.9 billion revenuebefore January 1, 2021. We expect that a prolonged coronavirus pandemic, the tax provisions of the CARES Act and any future coronavirus-related federal or state legislation could have a material impact on our effective tax rate and cash tax position.
In November 2018, the IRS issued proposed regulations addressing the interest disallowance rules contained in the Tax Act. For non-regulated businesses, the Tax Act enacted rules that set a cap on the amount of these excess deferred taxes as Regulatory Liabilities where it is probablebusiness interest that refunds willcan be made to customers in future rates. The amount and timing of any such refund cannot be determined at this time.
Beginning in 2018, PSEG, on a consolidated basis, will incur lower income tax expense resultingdeducted in a decrease in its projected effective income tax rate. This
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given year. Any amount that is also expected to increase PSEG’s and Power’s net income. To the extent alloweddisallowed can be carried forward indefinitely. Amounts recorded under the Tax Act Power’s operating cash flows will reflect the full expensing of capital investments for income tax purposes. PSEG and Power expect that the interest on their debt will continue to be fully tax deductible albeit at a lower tax rate. For PSE&G, the Tax Act is expected to lead to lower customer rates due to lower income tax expense recoveries and the refund of deferred income tax regulatory liabilities, partially offset by the impacts of higher rate base. The impact of the lower federal income tax rateCARES Act, such as depreciation and business interest disallowance, are subject to change based on PSE&G was reflected in PSE&G’s recently filed distribution base rate case and its transmission formula rate filings. The Tax Act is generally expected to result in lower operating cash flows for PSE&G resulting from the elimination of bonus depreciation, partially offset by higher revenues due to the higher rate base. The full impact of these and other provisions of the Tax Act cannot be determined at this time.
The impact of the Tax Act may differ from these estimates, possibly materially, due to,several factors, including among other things, the IRS and state taxing authorities issuing additional guidance and/or further clarification. Any further guidance or clarification could impact PSEG’s, PSE&G’s and PSEG Power’s financial statements.
In July 2018, New Jersey made changes in interpretations and assumptions PSEG has made, guidance that may be issued and actions PSEG may take as a result of the Tax Act. For additional information, see Note 20. Income Taxes.
Operational Excellence
We emphasize operational performance while developing opportunities in both our competitive and regulated businesses. Flexibility in our generating fleet has allowed us to take advantage of opportunitiesits income tax laws, including requiring corporate taxpayers to file in a rapidly evolving marketcombined reporting group as we remain diligentdefined under New Jersey law starting in managing costs. In 2017, our
diverse fuel mix2019. This provision includes an exemption for public utilities. We believe PSE&G meets the definition of a public utility and, dispatch flexibility allowed us to generate approximately 51 terra-watt hours while addressing

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fuel availability and price volatility,
total nuclear fleet achieved an average capacity factor of 94%, and
utility was recognized for the sixteenth consecutive year as the most reliable utilitytherefore, will not be included in the Mid-Atlantic region.
Financial Strength
Ourcombined reporting group. Any further guidance or clarification could impact PSEG’s and PSEG Power’s 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 2017 as we:
maintained sufficient liquidity,
maintained solid investment grade credit ratings, and
increased our indicative annual dividend for 2017 to $1.72 per share.
We expect to be able to fund our planned capital requirements, as described in Liquidity and Capital Resources, and manage the impacts of the Tax Act without the issuance of new equity.
Disciplined Investment
We utilize rigorous investment criteria when deploying capital and seek to invest in areas that complement our existing business and provide reasonable risk-adjusted returns. These areas include upgrading our energy infrastructure, responding to trends in environmental protection and providing new energy supplies in domestic markets with growing demand. In 2017, we
made additional investments in transmission infrastructure projects,
continued to execute our GSMP, Energy Strong, Energy Efficiency, solar and other existing BPU-approved utility programs,
continued construction of our Keys and Sewaren 7 generation projects for targeted commercial operation in 2018 and commenced construction of our BH5 generation project for targeted commercial operation in mid-2019, and
acquired six solar energy projects in various states totaling 88 MW-direct current (dc), for a total of 414 MW (dc) of installed capacity in 14 states throughout the U.S.statements.
Future Outlook
Our future success will depend on our ability to continue to maintain strong operational and financial performance in a slow-growing economy and a cost-constrained environment with low gas prices, to capitalize on or otherwise address appropriately regulatory and legislative developments that impact our business and to respond to the issues and challenges described below. In order to do this, we must continue to:
•obtain approval of and execute on our utility capital investment program, which includes the remainder of our recently approved CEF programs and other investments that yield contemporaneous and reasonable risk-adjusted returns, while enhancing the resiliency of our infrastructure, maintaining the reliability of the service we provide to our customers, and aligning our sustainability and climate goals with New Jersey’s energy policy,
•focus on controlling costs while maintaining safety, reliability and reliabilitycustomer 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 demand,
execute our utility capital investment program, including our Energy Strong program, GSMPprices and other investments for growth that yield contemporaneous and reasonable risk-adjusted returns, while enhancing the resiliency of our infrastructure and maintaining the reliabilitydemand, mindful of the service we providecost and affordability impacts to our customers,electric and obtain approvalgas distribution customers,
•advocate for extensionthe continuation of these programs,
effectively manage construction of our Keys, Sewaren 7, BH5the ZEC program to preserve New Jersey’s largest zero-carbon generation resource and other generation projects,
advocate for measures to ensure the implementation by PJM, FERC and FERCstate regulators of market design and transmission planning rules that continue to 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 investors,the communities in which we do business,
•finalize our strategic alternatives review for PSEG Power’s non-nuclear generating assets and successfully execute any transactions involving those assets as we transform our business mix into a mostly regulated utility and contracted generating company with a carbon-free nuclear and offshore wind fleet,
•successfully operate the LIPA T&D system and manage LIPA’s fuel supply and generation dispatch obligations.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.
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For 2018In 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 proceeding, settlement, investigation or claim, applicable to us and/or the energy industry,proceedings,
fair and timely rate relief from the BPU and FERC for recovery of costs and return on investments, including with respect to our distribution base rate case which was filed with the BPU in January 2018,
continuing discussions regarding the restructuring of GenOn and REMA and its potential impact on the value of our Keystone, Conemaugh and Shawville leveraged leases,
•the continuing impact of the ongoing coronavirus pandemic and the associated economic impact, which could extend beyond the duration of the pandemic,
•the continuing impacts of the Tax Act,
uncertainty in the national and regional economic recovery, continuing customer conservation efforts,CARES Acts and future changes in energy usage patternsfederal and evolving technologies, whichstate tax laws, and
•the impact customer behaviors and demand,
the potential for continued reductionsof changes in demand, and sustained lower natural gas and electricity prices, both at market hubs and the locations where we operate,
the impact of lower natural gas prices and increasing environmental compliance costs, onand expanded efforts to decarbonize several sectors of the competitiveness of our nuclear and remaining coal-fired generation plants, and the potential for retirement of such plants earlier than their current useful lives,economy.
delays and other obstacles that might arise in connection with the construction of our T&D, generation and other development projects, including in connection with permitting and regulatory approvals,
maintaining a diverse mix of fuels to mitigate risks associated with fuel price volatility and market demand cycles, and
FERC Staff’s continuing investigation of certain of Power’s New Jersey fossil generating unit bids in the PJM energy market.
Our primary investment opportunities are in two areas: our regulated utility business and our merchant power business. We continually assess a broad range of strategic options to maximize long-term stockholder value.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 employees, investors, regulators, customers and rating agencies; our existing indebtedness and restrictions it imposes; and tax considerations, among other things. Strategic options available to us include:
the acquisition, construction or disposition
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•investments in T&D facilities and/or generation units,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 and CEF-ES,
•the disposition or reorganizationrestructuring of our merchant generation business or portions thereof or other existing businesses or the acquisition or development of new businesses,
the expansion•investments in offshore wind with long-term contracts that provide predictability and a reasonable risk-adjusted return,
•continued operations of our geographic footprint,nuclear generation facilities, to the extent there is sufficient certainty that their operation will render an acceptable risk-adjusted return, and
continued•acquisitions, dispositions and other transactions involving assets or expanded participation in solar, demand responsebusinesses that could provide value to customers and energy efficiency programs, and
investments in capital improvements and additions, including the installation of environmental upgrades and retrofits, improvements to system resiliency, modernizing existing infrastructure and participation in transmission projects through FERC’s “open window” solicitation process.
Power is developing a retail energy business to sell energy, which we believe complements our existing wholesale marketing business. Power began these marketing activities in 2017 and has been granted retail energy supplier licenses in New Jersey, Pennsylvania and Maryland.shareholders.
There can be no assurance, however, that we will successfully develop and execute any of the strategic options noted above, or any additional options we may consider in the future. The execution of any such strategic plan may not have the expected benefits or may have unexpected adverse consequences.



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RESULTS OF OPERATIONS
 Years Ended December 31,
202020192018
Earnings (Losses)Millions
 PSE&G$1,327 $1,250 $1,067 
PSEG Power (A)594 468 365 
Other (B)(16)(25)6 
PSEG Net Income$1,905 $1,693 $1,438 
PSEG Net Income Per Share (Diluted)$3.76 $3.33 $2.83 
         
   Years Ended December 31, 
   2017 2016 2015 
 Earnings (Losses) Millions 
 PSE&G $973
 $889
 $787
 
 Power (A)(B) 479
 18
 856
 
 Other (B)(C) 122
 (20) 36
 
 PSEG Net Income $1,574
 $887
 $1,679
 
         
 PSEG Net Income Per Share (Diluted) $3.10
 $1.75
 $3.30
 
         
(A)PSEG Power’s results in 2020 include an after-tax gain of $86 million related to the sale of PSEG Power’s 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 PSEG Power’s ownership interests in the Keystone and Conemaugh fossil generation plants. PSEG Power’s results in 2018 include an after-tax gain of $39 million from the sale of its Hudson and Mercer coal/gas generation plants. See Item 8. Note 4. Early Plant Retirements/Asset Dispositions for additional information.
(A)Power’s results in 2017 and 2016 include after-tax expenses of $577 million and $396 million, respectively, related to the early retirement of its Hudson and Mercer coal/gas generation plants. See Item 8. Financial Statements and Supplementary Data—Note 3. Early Plant Retirements for additional information. Power’s results in 2015 include an after-tax insurance recovery for Superstorm Sandy of $102 million.
(B)Results in 2017
(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 non-cash net income benefit of $745 million, including $588 million related to Power and $147 million related to Energy Holdings, resulting from the remeasurement of deferred tax liabilities required due to the enactment of the Tax Act in December 2017.
(C)Other includes after-tax activities at the parent company, PSEG LI and Energy Holdings as well as intercompany eliminations. Energy Holdings recorded after-tax charges totaling $45 million and $92 million related to its investments in REMA’s leveraged leases in 2017 and 2016. See Item 8. Financial Statements and Supplementary Data—Note 7. Long-Term Investments and Note 8. Financing Receivables for further information.
Our results include the realized gains, losses and earnings on Power’s Nuclear Decommissioning Trust (NDT) Fund activity and otherthe impacts of non-trading commodity 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 activity. RealizedFund and MTM are shown in the following table:
Years Ended December 31,202020192018
Millions, after tax
NDT Fund and Related Activity (A) (B)$137 $152 $(90)
Non-Trading MTM Gains (Losses) (C)$(58)$205 $(84)
(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 are recorded in Other Income (Deductions), and impairments on certain NDT securities are recorded as Other-Than-Temporary Impairments. Interestinterest accretion expense on PSEG Power’s nuclear Asset Retirement Obligation (ARO) is recorded in O&MOperation & Maintenance (O&M) Expense and the depreciation related to the ARO asset is recorded in D&ADepreciation and Amortization (D&A) Expense.
Our results also include the after-tax impacts
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Table of non-trading mark-to-market (MTM) activity, which consistContents


(B)Net of the financial impact from positions with forward delivery dates.
The combined after-tax impact on Net Incometax (expense) benefit of $(94) million, $(103) million and $54 million for the years ended December 31, 2017, 20162020, 2019 and 2015 include2018, respectively.
(C)Net of tax (expense) benefit of $23 million, $(80) million and $33 million for the changes related to NDT Fundyears ended December 31, 2020, 2019 and MTM activity shown in the chart below:2018, respectively.
         
 Years Ended December 31, 2017 2016 2015 
   Millions, after tax 
 NDT Fund and Related Activity (A) $62
 $—
 $8
 
 Non-Trading MTM Gains (Losses) (B) $(99) $(100) $93
 
         
(A)Net of tax (expense) benefit of $(72) million, $(5) million and $(16) million for the years ended December 31, 2017, 2016 and 2015, respectively.
(B)Net of tax (expense) benefit of $68 million, $68 million and $(65) million for the years ended December 31, 2017, 2016 and 2015, respectively.
The 2017Our 2020 year-over-year increase of $212 million in our Net Income was driven primarily by:by
non-cash net income benefits•a gain on sale of PSEG Power’s ownership interest in the Yards Creek generating facility in 2020 (see Item 8. Note 4. Early Plant Retirements/Asset Dispositions),
•an asset impairment in 2019 related to new tax legislation (Seethe sale of PSEG Power’s interests in the Keystone and Conemaugh fossil generation plants (see Item 8. Financial Statements and Supplementary Data—Note 20. Income Taxes) at Power and Energy Holdings,4. Early Plant Retirements/Asset Dispositions),
•higher transmission revenues,
higher net NDT gains in 2017, and
lower charges relatedearnings due to investments in certain leveraged leasesT&D programs at Energy Holdings (See Item 8. Financial StatementsPSE&G, and Supplementary Data—Note 8. Financing Receivables).

•higher pension and OPEB credits,
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These increases were •partially offset by:by MTM losses in 2020 as compared to significant gains in 2019 at PSEG Power, and
higher charges related•a decrease at PSEG Power due to the early retirement of two coal/gas generation units at Power (See Item 8. Financial Statements and Supplementary Data—Note 3. Early Plant Retirements), and
lower average realized prices on lower volumes of energyelectricity sold at lower average realized sales pricesin PJM and under the BGS contracts, and in the PJM and New England regions.
The 2016 year-over-yearas well as lower capacity revenues, partially offset by a net decrease in our Net Income was driven primarily by:
charges related to the early retirementfuel costs and recognition of two coal/gas generation units at Power (See Item 8. Financial Statements and Supplementary Data—Note 3. Early Plant Retirements),
MTM losses in 2016 as compared to MTM gains in 2015,
lower volumesa full year of energy sold at lower average realized sales prices,
lower capacity and operating reserveZEC revenues in PJM,
higher 2016 congestion costs2020 which commenced in PJM due primarily to realized gains on financial transmission rights (FTR) in PJM in the prior year due to extremely cold weather,
lower volumes of gas sold at lower average prices under the BGSS contract,
insurance recoveries received primarily by Power in 2015 related to Superstorm Sandy, and
an impairment related to investments in certain leveraged leases at Energy Holdings (See Item 8. Financial Statements and Supplementary Data—Note 8. Financing Receivables).
These decreases were partially offset by:
lower generation costs driven by lower fuel costs, particularly for natural gas, and reduced generation output at Power,
•higher costs incurred at Power for planned outages in 2015,
higher transmission revenues, and
higher management fee revenues at PSEG LI pursuant to the OSA.


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PSEGApril 2019.
Our results of operations are primarily comprised of the results of operations of our principal operating subsidiaries, 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. Financial Statements and Supplementary Data—Note 24.26. Related-Party Transactions.
 Increase /
(Decrease)		Increase /
(Decrease)
Years Ended December 31,
 2020201920182020 vs. 20192019 vs. 2018
 MillionsMillions%Millions%
Operating Revenues$9,603 $10,076 $9,696 $(473)(5)$380 4 
Energy Costs3,056 3,372 3,225 (316)(9)147 5 
Operation and Maintenance3,115 3,111 3,069 4 — 42 1 
Depreciation and Amortization1,285 1,248 1,158 37 3 90 8 
(Gain) Loss on Asset Dispositions(123)402 (54)(525)(131)456 N/A
Income from Equity Method Investments14 14 15 — — (1)(7)
Net Gains (Losses) on Trust Investments253 260 (143)(7)(3)403 N/A
Other Income (Deductions)115 125 85 (10)(8)40 47 
Non-Operating Pension and OPEB Credits (Costs)249 177 76 72 41 101 N/A
Interest Expense600 569 476 31 5 93 20 
Income Tax (Benefit) Expense396 257 417 139 54 (160)(38)
                 
         
Increase /
(Decrease)
 
Increase /
(Decrease)
 
   Years Ended December 31,  
   2017 2016 2015 2017 vs. 20162016 vs. 2015 
   Millions Millions %
 Millions %
 
 Operating Revenues $9,084
 $9,061
 $10,415
 $23
 —
 $(1,354) (13) 
 Energy Costs 2,800
 3,001
 3,261
 (201) (7) (260) (8) 
 Operation and Maintenance 2,869
 3,008
 2,978
 (139) (5) 30
 1
 
 Depreciation and Amortization 1,986
 1,476
 1,214
 510
 35
 262
 22
 
 Income from Equity Method Investments 14
 11
 12
 3
 27
 (1) (8) 
 Other Income (Deductions) 228
 124
 152
 104
 84
 (28) (18) 
 Other-Than-Temporary Impairments 12
 28
 53
 (16) (57) (25) (47) 
 Interest Expense 391
 385
 393
 6
 2
 (8) (2) 
 Income Tax (Benefit) Expense (306) 411
 1,001
 (717) (174) (590) (59) 
                   
The 2017, 20162020, 2019 and 20152018 amounts in the preceding table for Operating Revenues and O&M costs each include $438$520 million, $410$490 million and $375$458 million, respectively, for Servco.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. Financial Statements and Supplementary Data—Note 4.5. Variable Interest Entity for further explanation. The Income Tax Benefit in 2017 includes the non-cash benefit resulting from the remeasurement of deferred tax liabilities required due to the enactment of the Tax Act in December 2017. 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)
 
   2017 2016 2015 2017 vs. 20162016 vs. 2015 
   Millions Millions %
 Millions %
 
 Operating Revenues $6,234
 $6,221
 $6,636
 $13
 —
 $(415) (6) 
 Energy Costs 2,363
 2,567
 2,722
 (204) (8) (155) (6) 
 Operation and Maintenance 1,434
 1,475
 1,560
 (41) (3) (85) (5) 
 Depreciation and Amortization 685
 565
 892
 120
 21
 (327) (37) 
 Other Income (Deductions) 87
 79
 75
 8
 10
 4
 5
 
 Interest Expense 303
 289
 280
 14
 5
 9
 3
 
 Income Tax Expense 563
 515
 470
 48
 9
 45
 10
 
                 
 Years Ended December 31,Increase /
(Decrease)		Increase /
(Decrease)
2020201920182020 vs. 20192019 vs. 2018
 MillionsMillions%Millions%
Operating Revenues$6,608 $6,625 $6,471 $(17)— $154 2 
Energy Costs2,469 2,738 2,520 (269)(10)218 9 
Operation and Maintenance1,614 1,581 1,575 33 2 6 — 
Depreciation and Amortization887 837 770 50 6 67 9 
Gain on Asset Dispositions(1)— — (1)N/A— — 
Net Gains (Losses) on Trust Investments3 2 (1)1 50 3 N/A
Other Income (Deductions)108 83 80 25 30 3 4 
Non-Operating Pension and OPEB Credits (Costs)205 150 59 55 37 91 N/A
Interest Expense388 361 333 27 7 28 8 
Income Tax Expense240 93 344 147 N/A(251)N/A
Year Ended December 31, 20172020 as compared to 20162019
Operating Revenuesincreased$13 decreased $17 million due to changes in delivery, clause, commodity and other operating revenues.
Delivery Revenuesincreased$166 million due primarily to an increase in transmission revenues. $219 million.
•Transmission revenues were $152increased $119 millionhigher due to higher revenue requirements calculated through our transmission formula rate, primarily to recover required investments.

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•Gas distribution revenues increased $30$4 million due to a $16 millionan increase due to Energy Strong, $10of $30 million from inclusioncollection of the GSMP in base rates $4 million in higher collections of GPRC and an increase of $2 million due to higher sales volumes. These increases were partially offset by lower Weather Normalization Clause (WNC)in WNC revenues of $2 million.
Electric distribution revenues decreased $16 million due primarily to a $28 million decrease in sales volume and $14 million in lower collections of GPRC, partially offset by a $26 million increase in Energy Strong revenues.
Clause Revenues increased $47 million due to the absence of the return in 2016 to customers of overcollections of Securitization Transition Charge (STC) revenues of $59 million and higher Margin Adjustment Clause (MAC) revenues of $4$19 million. These increases were partially offset by a $44 million decrease from lower Societal Benefitsales volumes and $1 million in lower collections of Green Program Recovery Charges (SBC)(GPRC).
•Electric distribution revenues increased $3 million due primarily to a $12 million increase in sales volumes, partially offset by $9 million in lower collections of $17GPRC.
•Transmission, electric distribution and gas distribution revenue requirements were $93 million higher as a result of a decrease in 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 $30 million due to $24 million in Tax Adjustment Credits (TAC) and GPRC deferrals and higher SBC charges of $13 million. These increases were partially offset by a $6 million reduction in Margin Adjustment Clause (MAC) revenues and $1 million in lower Solar Pilot Recovery Charge (SPRC) collections. The changes in STC,TAC and GPRC Deferrals, SBC, MAC and SBC amountsSPRC collections were entirely offset by the amortization of related costs (Regulatory Assets) in O&M, D&A and Interest Expense.and Tax Expenses. PSE&G does not earn margin on STC,TAC or GPRC deferrals or on SBC, Solar Pilot Recovery Charges (SPRC)MAC or MACSPRC collections.
Commodity Revenues decreased $204$344 million due to lower Gas revenues and lower Electric revenues partiallyrevenues. The changes in Commodity Revenues for both gas and electric are entirely offset by higher Gas revenues. This decrease is entirely offset with decreasedchanges in Energy Costs. PSE&G earns no margin on the provision of BGSbasic gas supply service (BGSS) and BGSSBGS to retail customers.
•Gas revenues decreased $195 million due primarily to lower BGSS sales volumes of $98 million and lower BGSS prices of $94 million.
•Electric revenues decreased $274$149 million due to $199 million in lower BGS revenues reflecting $109 million from lower sales volumes and $90$161 million from lower prices, $61partially offset by $12 million in lower collections of Non-Utility Generation Charges (NGC) due primarily to lower prices and $14 million in lower revenues from the decreasedhigher BGS sales volume of Non-Utility Generation (NUG) energy.volumes.
Gas revenuesOther Operating Revenues increased $70$78 million due to higher BGSS pricesincreases of $68$42 million in ZEC revenues and $2$33 million from higher sales volumes.in SREC revenues. The changes in ZEC revenues and SREC revenues are entirely offset by changes to Energy Costs.
Operating Expenses
Energy Costs decreased $204$269 million. This is entirely offset by changes in Commodity Revenues and Other Operating Revenues.
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Operation and Maintenance decreased $41 increased $33 million due primarily to
a $28 increases of $14 million net reduction related to various clause mechanisms and GPRCin gas distribution maintenance costs, $13 million in vegetation management, $9 million in transmission maintenance expenditures,
a $15 million decrease in appliance service costs, and
a $7 million net decrease in pensionstorm-related costs and OPEB expenses, net of amounts capitalized,
$4 million in distribution corrective and preventative maintenance expenditures. These increases were partially offset by a $9$4 million net increasedecrease in injuries and damages and a $10 million reduction in other operating expenses.
Depreciation and Amortizationincreased$120 $50 million due primarily to a $61 million net increase in amortization of Regulatory Assets, including the absence of the STC liability that ended in 2016, and an increase in depreciation of $59$45 million due to additional plant placed into service in 2017.and a $4 million increase from the amortization of regulatory assets and software.
Other Income (Deductions) increased $8$25 million due primarily to a $7 millionan increase in the Allowance for Funds Used During Construction (AFUDC). of $28 million, partially offset by a $3 million net decrease in solar loan interest and other.
Non-Operating Pension and OPEB Credits (Costs) increased $55 million due primarily to a $30 million increase in the expected return on plan assets, a $24 million decrease in interest cost and a $6 million decrease in amortization of the net actuarial loss, partially offset by a $5 million increase in the amortization of net prior service credit.
Interest Expense increased $14$27 million due primarily due to
$11 increases of $23 million and $12 million due to net long-term debt issuances in 20162020 and $9 million due to net long-term debt issuances in 2017,2019, respectively. These increases were partially offset by reductions of $7 million in interest expense related to short-term borrowings and in AFUDC.
a decrease of $6 million due to clause-related interest for BGSS in 2016.
Income Tax Expense increased $48$147 million due primarily to the reduction in the 2020 flowback of excess deferred income tax liabilities, higher pre-tax income.income in 2020, and an increase in the bad debt flow-through, partially offset by the tax benefit from changes in uncertain tax positions as a result of the settlement of the 2011-2016 federal income tax audits.
Year Ended December 31, 20162019 as compared to 20152018
Operating Revenues decreased $415 million due to changesSee Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations in delivery, clause, commodity and other operating revenues.our 2019 Annual Report.
Delivery Revenues increased $191 million due primarily to an increase in transmission revenues.
Transmission revenues were $223 million higher due to higher revenue requirements calculated through our transmission formula rate, primarily to recover required investments.
Electric distribution revenues decreased $27 million due primarily to $47 million in lower collections of GPRC, partially offset by an $18 million increase in Energy Strong revenues.

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Gas distribution revenues decreased $5 million due to a decrease of $43 million due to lower sales volumes and $7 million in lower collections of GPRC. These decreases were partially offset by higher WNC revenues of $25 million due to warmer weather in 2016 compared to 2015 and $20 million due to the inclusion of Energy Strong in base rates.
Clause Revenues decreased $445 million due to lower STC revenues of $419 million, lower SBC of $33 million and lower SPRC of $8 million. These decreases were partially offset by higher MAC revenues of $15 million. The changes in STC, SBC, SPRC and MAC amounts were entirely offset by changes in the amortization of related costs (Regulatory Assets) in O&M, D&A and Interest Expense. PSE&G does not earn margin on STC, SBC, SPRC or MAC collections.
Commodity Revenues decreased $155 million due to lower Electric and Gas revenues. This is entirely offset with decreased Energy Costs. PSE&G earns no margin on the provision of BGS and BGSS to retail customers.
Electric revenues decreased $136 million due to $73 million in lower collections of NGC due primarily to lower prices, $42 million in lower revenues from the sale of NUG energy and $21 million in lower prices BGS revenues primarily due to lower sales volumes.
Gas revenues decreased $19 million due to $80 million from lower sales volumes, partially offset by higher BGSS prices of $61 million.
Operating Expenses
Energy Costs decreased $155 million. This is entirely offset by Commodity Revenues.
Operation and Maintenance decreased $85 million due to
a $98 million net reduction related to various clause mechanisms and GPRC, and
a $13 million decrease in pension and OPEB expenses, net of amounts capitalized,
partially offset by $10 million of insurance recovery proceeds in 2015,
a $10 million increase in vegetation management costs, and
a $6 million net increase due primarily to T&D corrective maintenance and appliance service costs.
Depreciation and Amortization decreased $327 million due primarily to a $396 million net decrease in amortization of Regulatory Assets, partially offset by an increase in depreciation of $65 million due to additional plant in service in 2016.
Interest Expense increased $9 million due to increases of
$14 million due to net debt issuances in 2015, and
$13 million due to net debt issuances in 2016,
partially offset by a decrease of $11 million due to the redemption of securitization debt in 2015, and
$7 million of higher interest related to BGSS in 2015.
Income Tax Expense increased $45 million due primarily to higher pre-tax income partially offset by changes in the reserve for uncertain tax positions and flow through items.

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PSEG Power
 Years Ended December 31,Increase /
(Decrease)		Increase /
(Decrease)
2020201920182020 vs. 20192019 vs. 2018
 MillionsMillions%Millions%
Operating Revenues$3,634 $4,385 $4,146 $(751)(17)$239 6 
Energy Costs1,821 2,118 2,197 (297)(14)(79)(4)
Operation and Maintenance964 1,040 1,053 (76)(7)(13)(1)
Depreciation and Amortization368 377 354 (9)(2)23 6 
(Gain) Loss on Asset Dispositions(122)402 (54)(524)N/A456 N/A
Income from Equity Method Investments14 14 15 — — (1)(7)
Net Gains (Losses) on Trust Investments241 253 (140)(12)(5)393 N/A
Other Income (Deductions)12 54 21 (42)N/A33 N/A
Non-Operating Pension and OPEB Credits (Costs)33 21 15 12 57 6 40 
Interest Expense121 119 76 2 2 43 57 
Income Tax Expense (Benefit)188 203 66 (15)(7)137 N/A
                 
   Years Ended December 31, 
Increase /
(Decrease)
 
Increase /
(Decrease)
 
   2017 2016 2015 2017 vs. 20162016 vs. 2015 
   Millions Millions %
 Millions %
 
 Operating Revenues $3,930
 $4,023
 $4,928
 $(93) (2) $(905) (18) 
 Energy Costs 1,983
 1,986
 2,150
 (3) N/A
 (164) (8) 
 Operation and Maintenance 1,038
 1,143
 1,057
 (105) (9) 86
 8
 
 Depreciation and Amortization 1,268
 881
 291
 387
 44
 590
 N/A
 
 Income from Equity Method Investments 14
 11
 14
 3
 27
 (3) (21) 
 Other Income (Deductions) 157
 45
 97
 112
 N/A
 (52) (54) 
 Other-Than-Temporary Impairments 12
 28
 53
 (16) (57) (25) (47) 
 Interest Expense 50
 84
 121
 (34) (40) (37) (31) 
 Income Tax Expense (Benefit) (729) (61) 511
 (668) N/A
 (572) N/A
 
                 
Year Ended December 31, 20172020 as compared to 20162019
Operating Revenuesdecreased$93 $751 million due to changes in generation, gas supply and other operating revenues.
Generation Revenuesdecreased$204 $613 million due primarily to
•a net decrease of $126$369 million due to MTM losses in energy sales2020 as compared to MTM gains in the PJM and New England (NE) regions2019. Of this amount, there was a $196 million decrease due to losses on positions reclassified to realized upon settlement in 2020 compared to gains in 2019 coupled with a $173 million decrease due to changes in forward prices this year as compared to last year,
•a net decrease of $171 million due primarily to lower average realized prices in the PJM, New England (NE) and New York (NY) regions coupled with lower volumes sold in the PJM region primarily due to the sale of our ownership
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interests in the Keystone and Conemaugh generation plants in 2019. This was partially offset by higher volumes of electricity sold in the NE region, primarily due to the commencement of commercial operations of Bridgeport Harbor Unit 5 (BH5) in June 2019 and higher volumes of electricity sold in the NY region,
•a decrease of $100$79 million in electricity sold under our BGS contracts primarily due primarily to lower volumes coupled with lower prices, and
•a net decrease of $24$56 million in revenue expectedcapacity revenues due primarily to be returned to ratepayers associated with excess federal income tax previously collected by Power’s subsidiary, PSEG New Haven LLC, due to the changedecreases in federal tax rates effective January 1, 2018,
a decrease of $18 million in operating reservesauction prices in the PJM region coupled with lower volumes due to the sale of our ownership interests in Keystone and Conemaugh generation plants,
a charge•partially offset by an increase of $10$70 million due to an increaseZEC revenues that started in April 2019 coupled with increased generation at the FERC accrual related to the PJM bidding matter,nuclear plants in 2020.
a decrease of $7 million due to higher MTM losses in 2017 as compared to 2016. Of this amount, $120 million was due to increased forward prices, partially offset by a decrease of $113 million due to lower gains on positions reclassified to realized upon settlement in 2017 as compared to 2016,
partially offset by a net increase of $53Gas Supply Revenues decreased $138 million due primarily to higher volumes
•a decrease of electricity sold under wholesale load contracts in the PJM and NE regions,
a net increase of $18 million in capacity revenues in the PJM and NE regions due to increases in cleared capacity and capacity auction prices, and
an increase of $11 million due to higher sales related to new solar projects.
Gas Supply Revenuesincreased $110 million due primarily to
an increase of $67$153 million in sales under the BGSS contract, of which $40$99 million was due to highera decrease in sales volumes and $54 million to lower average sales prices, coupled with a $27 million increase in sales volumes due to periods of colder weather in the heating season,
•partially offset by a net increase of $24 million due to higher MTM gains in 2017 as compared to 2016, and
an increase of $19$18 million related to sales to third parties, of which $48$80 million was due to higher average sales prices,volumes sold, partially offset by $29$62 million ofdue to lower volumes sold.




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average sales prices.
Operating Expenses
Energy Costs represent the cost of generation, which includes fuel costs for generation as well as purchased energy in the market, and gas purchases to meet PSEG Power’s obligation under its BGSS contract with PSE&G. Energy Costs decreased $3$297 million due to
Generation costs decreased $69$156 million due primarily to
•a net decrease of $83$176 million primarily due to lower congestion costs in PJM due to lower rates coupled with less volumes, partially offset by higher transmission charges due to higher rates,
a net decrease of $50 million due to charges associated with the announced early retirement of the Mercer and Hudson units in 2016, primarily related to lower coal inventory write-downs in 2017, partially offset by additional retirement costs incurred in 2017,
partially offset by higher fuel costs of $31 million reflecting higher average realizedlower gas prices for natural gasin the PJM and NY regions coupled with the utilization of higher volumes of coal, partially offset by the utilization of lower volumes of coal in the PJM region primarily due to the sale of our ownership interests in the Keystone and Conemaugh generation plants, and lower volumes of gas in the PJM region. This was partially offset by utilization of higher volumes of gas in the NE region due to the commencement of commercial operations at BH5 in June 2019 coupled with utilization of higher volumes of gas in the NY region, and
an increase•a net decrease of $17$5 million due to less MTM losses in 20172020 as compared to MTM gains in 2016, and2019,
•partially offset by a net increase of $16$24 million in higher emission costs primarily due to an increaseNew Jersey reentering the RGGI program beginning in the volume of energy purchases in the NE region to serve load obligations.2020.
Gas costs increased $66 decreased $141 million due primarily to
an increase•a decrease of $50$160 million related to sales under the BGSS contract, of which $31$80 million was due to highera decrease in the average cost of gas costs, coupled withand $80 million to a $19decrease in send out volumes. Included in the average cost of gas were $18 million increase in volumes soldof interstate gas pipeline refunds due to a settlement on pipeline rates from prior periods, of colder weather in the heating season, and
an•partially offset by a net increase of $16$18 million related to sales to third parties, of which $44$73 million was due to higher average gas costs,volumes sold, partially offset by $55 million due to a $28 million decrease in volumes sold.the average cost of gas.
Operation and Maintenance decreased $105$76 million due primarily to
a $72 millionnet decrease at our fossil plants due primarily to the retirementsale of our ownership interests in the HudsonKeystone and Mercer unitsConemaugh generation plants in September 2019 and our ownership interest in the Yards Creek generation facility in September 2020, as well as a goodwill impairment charge of $16 million in 2019 for the write down of PSEG Power’s carrying value to fair value, partially offset by higher planned outage costs in 2016,2020.
a $35Depreciation and Amortization decreased $9 million net decrease related to our nuclear plants due primarily to lower labor-related expenses and outage costs,
an $8 million net decrease due to lower pension and OPEB costs,
extension of the Peach Bottom License which was approved by the NRC in March 2020, partially offset by an increased asset base at Nuclear. 
(Gain) Loss on Asset Dispositions reflects a gain on the sale of our ownership interest in the Yards Creek generation facility in September 2020 and a loss on the sale of our ownership interests in the Keystone and Conemaugh generation plants in 2019. See Item 8. Note 4. Early Plant Retirements/Asset Dispositions.
Net Gains (Losses) on Trust Investments decreased $12 million due primarily to a $76 million decrease in net unrealized gains on equity investments in the NDT Fund, partially offset by a $66 million increase in net realized gains on NDT Fund investments.
Other Income (Deductions) decreased $42 million primarily due to purchases of NOLs in 2020 under New Jersey’s Technology Tax Benefit Transfer Program and lower interest and dividend income on NDT Fund investments.
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Non-Operating Pension and OPEB Credits (Costs) increased $12 million due to a $9 million decrease in interest cost, a $5 million increase in the expected return on plan assets, and a $3 million decrease in the amortization of costs relatedthe net actuarial loss, partially offset by a $3 million increase in co-owner charges and a $2 million decrease in the amortization of net prior service credit.
Interest Expense increased $2 million due primarily to new solar plants$17 million of lower capitalized interest in 2020 as a result of BH5 being placed into service in 2017.
Depreciation and Amortization increased $387 million due primarily to
$346 million2019, partially offset by a decrease of higher depreciation for Hudson and Mercer, primarily due to the accelerated expense related to the early retirement of those units,
a $15 million increase due to the accelerated retirement date for the Bridgeport Harbor unit 3,
an $11 million increase due primarily to a higher nuclear asset base, and
$11 million of higher depreciation due to new solar projects.
Other Income (Deductions) increased $112 million due primarily to higher net realized gains from the NDT Fund in 2017.
Other-Than-Temporary Impairments decreased $16 million due to lower impairments of equity securities in the NDT Fund in 2017.
Interest Expense decreased $34 million due primarily to
a $24 million decrease due to higher interest capitalized for the construction of three new fossil stations: BH5, Sewaren 7 and Keys, and
a net $7 million decrease due to debt maturities in September 2016, partially offset by a debt issuance in June 2016.April 2020.
Income Tax Expense decreased $668$15 million due primarily to the one-time benefit recordedof purchasing 2019 NOLs under the New Jersey Technology Tax Benefit Transfer Program in 2020, and the tax benefit from changes in uncertain tax positions as a result of the remeasurement of deferred tax balances required due to the enactmentsettlement of the Tax Act in December 2017.2011-2016 federal income tax audits, partially offset by higher pre-tax income.

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Year Ended December 31, 20162019 as compared to 20152018
Operating Revenues decreased $905 million due to changesSee Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations in generation, gas supply and other operating revenues.our 2019 Annual Report.
Generation Revenues decreased $714 million due primarily to
a decrease of $317 million due to MTM losses in 2016 as compared to MTM gains in 2015. Of this amount, $199 million was due to changes in forward power prices resulting in lower MTM gains in 2016 compared to 2015. Also contributing to the decrease was $118 million of higher gains on positions reclassified to realized upon settlement in 2016 compared to 2015,
a decrease of $298 million in energy sales volumes in the PJM, NE and NY regions due primarily to milder weather in 2016 and lower average realized prices,
a decrease of $80 million in capacity revenue primarily in the PJM region due to the retirement of older peaking units in June 2015, and
a decrease of $49 million due to lower operating reserve revenues in the PJM region due to less congestion and lower prices,
partially offset by a net increase of $19 million due primarily to higher volumes of electricity sold under wholesale load contract in the PJM and NE regions, partially offset by lower average prices, and
a net increase of $8 million due to new solar projects beginning commercial operations.
Gas Supply Revenues decreased $191 million due primarily to
a decrease of $183 million in sales under the BGSS contract due primarily to lower average sales prices and a decrease in sales volumes due to warmer average temperatures in the 2016 heating season, and
a decrease of $9 million due to MTM losses in 2016 due to changes in forward prices.
Operating Expenses
Energy Costs represent the cost of generation, which includes fuel costs for generation as well as purchased energy in the market, and gas purchases to meet Power’s obligation under its BGSS contract with PSE&G. Energy Costs decreased $164 million due to
Generation costs decreased $95 million due primarily to
lower fuel costs of $288 million reflecting lower average realized prices for natural gas and the utilization of lower volumes of fuel,
partially offset by a net increase of $143 million primarily due to realized gains on FTRs in PJM in 2015 due to extremely cold weather, and
a $62 million charge associated with the announced early retirement of the Mercer and Hudson units, primarily related to a coal inventory write-down.

Gas costs decreased $69 million due to
a decrease of $101 million related to sales under the BGSS contract due primarily to lower average gas costs and a decrease in volumes sold due to warmer average temperatures during the 2016 winter heating season,
partially offset by an increase of $32 million related to sales to third parties due primarily to higher average gas costs and an increase in volumes sold.
Operation and Maintenance increased $86 million due to
$145 million of insurance recoveries received in 2015 related to Superstorm Sandy, and
$53 million of charges related to the early retirement of the Hudson and Mercer units,
partially offset by a net decrease of $73 million related to our fossil plants, largely due to higher costs incurred in 2015 for our planned major outages at the Bethlehem Energy Center and Bergen generating plants,
a net decrease of $31 million related to our nuclear plants due primarily to lower planned outage costs at our 100%-owned Hope Creek plant and our 57%-owned Salem Unit 1 plant, and
an $8 million decrease due to lower pension and OPEB costs.

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Depreciation and Amortization increased $590 million due primarily to
$555 million of accelerated depreciation due to the early retirement of the Hudson and Mercer units,
a $24 million increase due primarily to a higher nuclear asset base, and
$5 million of higher depreciation due to new solar projects
Other Income (Deductions) decreased $52 million due primarily to $28 million of insurance recoveries received in 2015 related to Superstorm Sandy and $38 million of lower net realized gains from the NDT Fund in 2016, partially offset by $10 million of lower purchased tax credits in 2016.
Other-Than-Temporary Impairments decreased $25 million due to lower impairments of equity securities in the NDT Fund in 2016.
Interest Expense decreased $37 million due to
$27 million of interest capitalized for the construction of three new fossil stations: Bridgeport Harbor 5, Sewaren 7 and Keys Energy Center, and
a $15 million decrease due to the maturity of 5.50% of Senior Notes in December 2015,
partially offset by an increase of $5 million due to net debt issuances in 2016.
Income Tax Expense decreased $572 million in 2016 due primarily to a pre-tax loss in 2016 as compared to pre-tax income in 2015.
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. PSEG LI’s subsidiary, Long Island Electric Utility Servco LLC (Servco), does not participate in the corporate money pool. Servco’s short-term liquidity needs are met through an account funded and owned by LIPA.
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.$1.5 billion. These facilities are available to back-stop PSEG’s commercial paper program, issue letters of credit and for general corporate purposes. These facilities may also be used to provide support to PSEG’s subsidiaries. PSEG’s credit facilities and the commercial paper program are available to support PSEG working capital needs or to temporarily fund growth opportunities in advance of obtaining permanent financing. PSEGPSEG’s credit facilities are also has a $700 million term loan credit agreement that is scheduledavailable to expire in June 2019. From time to time, PSEG may make equity contributions or provide creditliquidity support to its subsidiaries.
PSEG Power’s sources of external liquidity include $2.1 billion of multi-year revolving credit facilities. Additionally, from time to time, PSEG Power maintains bilateral credit agreements designed to enhance its liquidity position. Credit capacity is primarily used to provide collateral in support of PSEG Power’s forward energy sale and forward fuel purchase contracts as the market prices for energy and fuel fluctuate, and to meet potential collateral postings in the event that PSEG Power is downgraded to below investment grade by Standard & Poor’s (S&P&P) or Moody’s. PSEG Power’s dividend payments to PSEG are also designed to be consistent with its capital structure objectives

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which have been established to maintain investment grade credit ratings and provide sufficient financial flexibility. Generally, PSEG Power issues senior unsecured debt to raise long-term capital.
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 provide opportunities for shareholder dividend payments.dividends.
For the year ended December 31, 2017, our operating cash flow decreased by $50 million. For the year ended December 31, 2016,2020, our operating cash flow decreased by $608$277 million. The net changes weredecrease was primarily due to net tax payments at PSEG and its other subsidiaries in 2017 offset bythe net changes from our subsidiaries, as discussed below.below, and higher tax payments in 2020 at Energy Holdings, offset by net tax refunds in 2020 as compared to net tax payments in 2019 at the parent company.
Given the current economic challenges, PSE&G has informed both our residential customers and state regulators that all non-safety related service disconnections for non-payment will be temporarily suspended. In addition, the current economic
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conditions have adversely impacted residential and C&I customer payment patterns. 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 extend beyond the duration of the coronavirus pandemic. While the impact on our results of operations, financial condition and cash flows for the year ended December 31, 2020 was not material, a prolonged coronavirus pandemic and the associated economic impacts, which could extend beyond the duration of the pandemic, could materially impact cash from operations, Accounts Receivable and bad debt expense.
PSE&G
PSE&G’s operating cash flow decreased $55$82 million from $1,894$2,035 million to $1,839$1,953 million for the year ended December 31, 2017,2020, as compared to 2016,2019, due primarily to lowertax payments in 2020 as compared to tax refunds in 2019, increased regulatory deferrals and a decreasehigher Accounts Receivable reflecting lower collections due to the economic impacts of $50 million related to a change in regulatory deferrals. These amounts werethe pandemic and the moratorium on collections, partially offset by higher earnings and $30 milliondecreases in decreasedelectric energy and vendor payments.payables.
PSE&G’s    PSEG Power
PSEG Power’s operating cash flow decreased $231$368 million from $2,125$1,479 million to $1,894$1,111 million for the year ended December 31, 2016,2020, as compared to 2015,2019, due primarily to a decrease$359 million reduction resulting from lower collections for securitization debt principal repayments which were $259 milliona modest increase in 2015, a decrease of $249 millioncounterparty cash collateral posting requirements in cash receipts from customers due to lower sales driven by warmer winter weather in 20162020 as compared to 2015, a decrease of $90 million relatedsignificant reduction in postings in 2019, and tax payments in 2020 as compared to a changetax refunds in regulatory deferrals, primarily driven by net returns to customers in 2016 related to 2015 overcollections, partially offset by higher bill credits and $74 million in increased vendor payments. These amounts were2019, partially offset by higher earnings and higher tax refunds in 2016.
Power
Power’s operating cash flow increased $71 million from $1,255 million to $1,326 million for the year ended December 31, 2017, as compared to 2016, primarily resulting from a decrease of $61 million in payments to counterparties, a $26$51 million increase from higher net collections of counterparty receivables, and higher earnings. These amounts were partially offset by higher tax payments and an increase in margin deposit requirements of $14 million.
Power’s operating cash flow decreased $451 million from $1,706 million to $1,255 million for the year ended December 31, 2016, as compared to 2015, primarily resulting from lower earnings, an increase in margin deposit requirements of $198 million, and a $134 million decrease from net collection of counterparty receivables, partially offset by a reduction in tax payments.receivables.
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.
In March 2020, PSEG entered into a $300 million, 364-day term loan agreement, which was prepaid in January 2021. This term loan is not included in the credit facility amounts presented in the following table. In April 2020, PSEG entered into two 364-day term loan agreements for $200 million and $300 million which were prepaid in August 2020.
Our total credit facilities and available liquidity as of December 31, 20172020 were as follows:
Company/FacilityAs of December 31, 2020
Total
Facility		UsageAvailable
Liquidity
 Millions
PSEG$1,500 $665 $835 
PSE&G600 117 483 
PSEG Power2,100 168 1,932 
Total$4,200 $950 $3,250 
         
 Company/Facility As of December 31, 2017 
 
Total
Facility
 Usage 
Available
Liquidity
 
   Millions 
 PSEG $1,500
 $556
 $944
 
 PSE&G 600
 15
 585
 
 Power 2,100
 151
 1,949
 
 Total $4,200
 $722
 $3,478
 
         
As of December 31, 2017,2020, our credit facility capacity was in excess of our projected maximum liquidity requirements over our 12-month12 month planning horizon.horizon, including access to capital to meet redemptions. Our maximum liquidity requirements are based on stress scenarios that incorporate changes in commodity prices and thepotential impact of PSEG Power losing its investment grade credit rating from S&P or Moody’s, which would represent a three level downgrade from its current S&P or Moody’s 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 $848$840 million and $783$974 million as of December 31, 20172020 and 2016,2019, respectively. The early retirement of Power’s Hudson and Mercer coal/gas generation units did not have a material impact on Power’s debt covenant ratios or its ability to obtain credit facilities. See Item 8. Financial Statements and Supplementary Data—Note 3. Early Plant Retirements.

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For additional information, see Item 8.Financial Statements and Supplementary Data—8. Note 14.16. Debt and Credit Facilities.
Long-Term Debt Financing
PSE&GDuring the next twelve months,
•PSEG has $400 million of 5.30% Medium Term Notes maturing in May 2018 and $350 million of 2.30% Medium Term Notes maturing in September 2018.
Power has $250$300 million of 2.45%2.00% Senior Notes maturing in November 2018.2021,
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•PSE&G has $300 million of 1.90% Medium-Term Notes, Series K, maturing in March 2021 and $134 million of 9.25% Mortgage Bonds Series CC maturing in June 2021, and
•PSEG Power has $700 million of 3.00% Senior Notes maturing in June 2021 and $250 million of 4.15% Senior Notes maturing in September 2021.
For a discussion of our long-term debt transactions during 2017 and into 2018,2020, see Item 8. Financial Statements and Supplementary Data—Note 14.16. Debt and Credit Facilities.
Guarantor Financial Information
PSEG Power’s Senior Notes are fully and unconditionally guaranteed on a joint and several basis by its subsidiaries, PSEG Fossil LLC, PSEG Nuclear LLC and PSEG Energy Resources & Trade LLC. Each guarantor subsidiary is a wholly owned consolidated subsidiary of PSEG Power.
Summarized financial information is being presented, on a combined basis, only for PSEG Power (parent company) and the guarantors of PSEG Power’s Senior Notes, excluding investments in, and earnings (losses) from, subsidiaries that are not guarantors. All transactions between PSEG Power (parent company) and the guarantor subsidiaries are eliminated in the combined summarized financial information. The required disclosures for the most recent fiscal year have been moved outside the Notes to Consolidated Financial Statements and are provided in the following tables.
Year Ended
December 31, 2020
Millions
Operating Revenues (A)$3,564 
Operating Income$598 
Net Income$597 
(A)Operating Revenues include sales to affiliates of $1,218 million.
As of
December 31, 2020
Millions
Current Receivables from Subsidiaries and Affiliates$2,350 
Total Current Assets$3,365 
Noncurrent Receivables from Affiliates$17 
Total Noncurrent Assets$7,228 
Current Payables to Subsidiaries and Affiliates$258 
Total Current Liabilities$1,734 
Noncurrent Payables to Affiliates$57 
Total Noncurrent Liabilities$4,027 
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, 2017,2020, PSE&G’s Mortgage coverage ratio was 5.23.3 to 1 and the Mortgage would permit up to approximately $6.9$7.1 billion aggregate principal amount of new Mortgage Bonds to be issued against additions and improvements to its property.
For a discussion of the potential impact on our debt covenants from our strategic alternatives, see Item 1A. Risk Factors.
Default Provisions
Our bank credit agreements and indentures contain various, customary default provisions that could result in the potential
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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, that 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 and outstanding notes also contain limitations on the incurrence of subsidiary debt and liens and certain of PSEG Power’s outstanding notes require PSEG Power to repurchase such notes upon certain change of control events.
There are no cross accelerationcross-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. PSEG Power’s indenture includes a cross acceleration provision similar to that described above for PSEG’s existing notes except that such provision may be triggered upon the acceleration of more than $50 million of indebtedness incurred by PSEG Power or any of its subsidiaries. Such provision does not cross accelerate to PSEG, any of PSEG’s subsidiaries (other than PSEG Power and its subsidiaries), PSE&G or any of PSE&G’s subsidiaries.
Ratings Triggers
Our debt indentures and credit agreements do not contain any material ‘ratings triggers’“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.

Pension and NDT Fund Obligations
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TableIRS minimum funding requirements for pension plans are determined based on the fund’s assets and liabilities at the end of Contentsa calendar year for the subsequent calendar year. As a result, the market volatility in 2020 associated with the ongoing coronavirus pandemic is not expected to impact PSEG’s pension contributions in 2021. In the event of a prolonged economic downturn associated with the ongoing coronavirus pandemic, our contributions to the pension plans may increase in future periods to meet IRS minimum funding requirements. PSEG hadaccumulated funding credits totaling approximately $600 million through 2020, which represent historical contributions in excess of IRS minimum funding requirements, and these credits can be applied to offset any future cash contribution obligations.


In addition, the NRC requires a biennial filing of the NDT fund balances against the decommissioning liability estimate. Any funding shortfalls are required to be cured prior to the next NRC reporting period. The market volatility associated in 2020 with the ongoing coronavirus pandemic did not result in any supplemental required funding of the NDT Fund. To the extent of a prolonged economic downturn associated with the ongoing coronavirus pandemic, our funding requirements may increase in future periods to meet NRC minimum funding requirements.
Common Stock Dividends
Years Ended December 31,
Dividend Payments on Common Stock202020192018
Per Share$1.96 $1.88 $1.80 
in Millions$991 $950 $910 
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 Years Ended December 31, 
 Dividend Payments on Common Stock 2017 2016 2015 
 Per Share $1.72
 $1.64
 $1.56
 
 in Millions $870
 $830
 $789
 
         
On February 20, 2018,16, 2021, our Board of Directors approved a $0.45$0.51 per share of common stock dividend for the first quarter of 2018.2021. This reflects an indicative annual dividend rate of $1.80$2.04 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. Financial Statements and Supplementary Data—Note16.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 Corporate Credit Ratings (S&P) and Issuer Credit Ratings (Moody’s) and can be Stable, Negative, or Positive. There is no assurance that the ratings will continue for any given period of time or that they will not be revised by the rating agencies, if in their respective judgments, circumstances warrant. Each rating given by an agency should be evaluated independently of the other agencies’ ratings. The ratings should not be construed as an indication to buy, hold or sell any security.
In April 2017,August 2020, S&P published updated research and affirmed the ratings and outlooks onlowered PSEG and PSE&G. In June 2017, S&P published updated research on Power and the rating and outlook remained unchanged. In July 2017, Moody’s upgraded PSEG’s senior unsecuredPower’s Senior Note rating to Baa1BBB from Baa2 and revised its outlook to Stable from Positive. Also in July, Moody’s affirmed the ratings at PSE&G and Power.
BBB+.
Moody’s (A)S&P (B)
PSEGMoody’s (A)S&P (B)
PSEG
OutlookStableStable
Senior NotesBaa1BBB
Commercial PaperP2A2
PSE&G
OutlookStableStable
Mortgage BondsAa3A
Commercial PaperP1A2
Power
OutlookStableStable
Senior NotesBaa1BBB+
(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.OutlookStableStable
Senior NotesBaa1BBB
Commercial PaperP2A2
PSE&G
(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.OutlookStableStable
Mortgage BondsAa3A
Commercial PaperP1A2
PSEG Power
OutlookStableStable
Senior NotesBaa1BBB
(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 IncomeLoss
For the year ended December 31, 2017,2020, we had an Other Comprehensive IncomeLoss of $34$15 million on a consolidated basis. The Other Comprehensive IncomeLoss was due primarily to a $44decrease of $46 million increase inrelated to pension and other postretirement benefits, partially offset by $25 million of net unrealized gains related to Available-for-Sale Securities, partially offset by a decrease of $8 million in our consolidated liability for pension and postretirement benefits and $2$6 million of unrealized lossesgains on derivative contracts accounted for as hedges. See Item 8. Financial Statements and Supplementary Data—Note 21.23. Accumulated Other Comprehensive Income (Loss), Net of Tax for additional information.

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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 table below.following table. These projections include Allowance for Funds Used During ConstructionAFUDC and Interest Capitalized During Construction for PSE&G and PSEG Power, respectively. These amounts are subject to change, based on various factors. Amounts shown below for Energy Strong, GSMP and Solar/Energy Efficiency programs are forPSE&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. We will also continue to approach potential growth investments for PSEG Power opportunistically, seeking projects that will provide attractive risk-adjusted returns for our shareholders.
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   2018 2019 2020 
     Millions   
 PSE&G:       
 Transmission $1,235
 $1,290
 $1,280
 
 Distribution 1,015
 715
 705
 
 Energy Strong 35
 —
 —
 
 Gas System Modernization Program 300
 40
 —
 
 Solar/Energy Efficiency 85
 75
 55
 
 Total PSE&G $2,670
 $2,120
 $2,040
 
 Power:       
 Baseline $170
 $165
 $165
 
 Fossil Growth Opportunities 445
 65
 10
 
 Other 30
 30
 20
 
 Total Power $645
 $260
 $195
 
 Other $40
 $30
 $20
 
 Total PSEG $3,355
 $2,410
 $2,255
 
   

     
202120222023
 Millions 
PSE&G:
Transmission$955 $890 $645 
Electric Distribution695 790 1,055 
 Gas Distribution875 870 985 
Clean Energy200 375 400 
Total PSE&G$2,725 $2,925 $3,085 
PSEG Power100 120 150 
Other25 30 25 
Total PSEG$2,850 $3,075 $3,260 
PSE&G
PSE&G’s projections for future capital expenditures include material additions and replacements to its transmission and distributionT&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.
•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.
Energy Strong—Electric and Gas Distribution reliability investment program focused on system hardening and resiliency.
Gas System Modernization Program—Gas Distribution investment program to replace aging infrastructure.
Solar/Energy Efficiency—•Clean Energy—investments associated with grid-connected solar, solar loan programs, and customer energy efficiency programs.

programs, and infrastructure supporting electric vehicles.
In November 2017,September 2020, the BPU issued an orderOrder approving our CEF-EE program, authorizing PSE&G’s net&G to commit $1 billion over a three-year period, with the majority of the investment of $100occurring over a five-year period. In January 2021, the BPU issued an Order approving our CEF-EC program, authorizing PSE&G to invest approximately $700 million on the CEF-EC program over a four-year period. Also in January 2021, the BPU issued an Order approving our CEF-EV program, authorizing PSE&G to rebuild New Jersey Transit’s Mason electric distribution substation and related facilities in Kearny, New Jersey. This projectinvest $166 million over what is expected to be completed in December 2021.

a six-year period. See Executive Overview of 2020 and Future Outlook for additional information.
In July 2017, PSE&G filed a petition with the BPU requesting approval of the $2.7 billion next phase of the Gas System Modernization Program (GSMP II) and associated cost recovery mechanism. The GSMP II program will enable PSE&G to continue to accelerate the replacement of its aging cast-iron and unprotected steel gas pipes. This matter is currently pending before the BPU and is not included in the PSE&G’s projected capital expenditures above.

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In 2017,2020, PSE&G made $2,919$2,507 million of capital expenditures, primarily for transmission and distributionT&D system reliability. This does not include expenditures for cost of removal, net of salvage, of $107$106 million, which are included in operating cash flows.
    PSEG Power
PSEG Power’s projected expenditures for the various items listed above are primarily comprised of the following:
Baseline—investments to replace major parts and enhance operational performance.
Fossil Growth Opportunities—investments associated with new construction, including Keys, Sewaren 7 and BH5, and with upgrades to increase efficiency and output at combined cycle plants.
Other—includes investments made in response to environmental, regulatory and legal mandates and other capital projects.
In 2017,2020, PSEG Power made $1,040$195 million of capital expenditures, excluding $191$209 million for nuclear fuel, primarily related to various projects at Fossil, Solarnuclear and Nuclear.solar projects.

Offshore Wind
The above table does not reflect our expected long-term investments in offshore wind projects. Following the completion of our acquisition of a 25% equity interest in Orsted’s Ocean Wind project, which is subject to the approval of the BPU and other customary closing conditions, we currently expect to make investments in the project in 2021 relating to our initial capital investment and to fund construction and operations planning activities. Over the course of the project, which could provide first power in late 2024, our investments are expected to be substantial.
Disclosures about Contractual Obligations
The following table reflects our contractual cash obligations in the respective periods in which they are due. In addition, the table summarizes anticipated debt maturities for the years shown. For additional information, see Item 8. Financial Statements and Supplementary Data—Note 14.16. Debt and Credit Facilities.
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The table below does not reflect any anticipated cash payments for pension obligations due to uncertain timing of payments or liabilities for uncertain tax positions since we are unable to reasonably estimate the timing of liability payments in individual years beyond 12 months due to uncertainties in the timing of the effective settlement of tax positions. See Item 8. Financial Statements and Supplementary Data—Note 20.22. Income Taxes for additional information.
Total
Amount
Committed		Less
Than
1 Year		2 - 3
Years		4 - 5
Years		Over
5 Years
 Millions
Contractual Cash Obligations
Long-Term Recourse Debt Maturities
PSEG$2,946 $300 $700 $1,300 $646 
PSE&G10,999 434 825 1,100 8,640 
PSEG Power2,348 950 994 — 404 
Interest on Recourse Debt
PSEG315 68 105 54 88 
PSE&G6,650 390 756 683 4,821 
PSEG Power487 93 132 70 192 
Operating Leases
PSE&G127 16 24 18 69 
PSEG Power89 14 22 6 47 
Services150 15 30 30 75 
Energy-Related Purchase Commitments
PSEG Power2,252 688 804 477 283 
Total Contractual Cash Obligations$26,363 $2,968 $4,392 $3,738 $15,265 
Liability Payments for Uncertain Tax Positions
PSEG$12 $12 $— $— $— 
PSE&G12 12 — — — 
PSEG Power— — — — — 
             
   
Total
Amount
Committed
 
Less
Than
1 Year
 
2 - 3
Years
 
4- 5
Years
 
Over
5 Years
 
   Millions 
 Contractual Cash Obligations           
 Long-Term Recourse Debt Maturities           
 PSEG $2,100
 $—
 $1,100
 $1,000
 $—
 
 PSE&G 8,658
 750
 759
 434
 6,715
 
 Power 2,400
 250
 450
 950
 750
 
 Interest on Recourse Debt           
 PSEG 157
 49
 65
 43
 —
 
 PSE&G 5,186
 313
 578
 525
 3,770
 
 Power 821
 113
 202
 129
 377
 
 Capital Lease Obligations           
 Power 2
 1
 1
 —
 —
 
 Operating Leases           
 PSE&G 113
 16
 17
 15
 65
 
 Power 58
 5
 9
 6
 38
 
 Services 194
 14
 30
 30
 120
 
 Other 6
 1
 2
 2
 1
 
 Energy-Related Purchase Commitments           
 Power 2,670
 730
 938
 468
 534
 
 Total Contractual Cash Obligations $22,365
 $2,242
 $4,151
 $3,602
 $12,370
 
             
 Liability Payments for Uncertain Tax Positions           
 PSEG $69
 $69
 $—
 $—
 $—
 
 PSE&G 35
 35
 —
 —
 —
 
 Power 30
 30
 —
 —
 —
 
             

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OFF-BALANCE SHEET ARRANGEMENTS
PSEG and PSEG Power issue guarantees, primarily in conjunction with certain of PSEG Power’s energy contracts. See Item 8. Financial Statements and Supplementary Data—Note 13.15. Commitments and Contingent Liabilities for further discussion.
Through Energy Holdings, we have investments in leveraged leases that are accounted for in accordance with GAAP Accounting for Leases. Leveraged lease investments generally involve three parties: an owner/lessor, a creditor and a lessee. In a typical leveraged lease arrangement, the lessor purchases an asset to be leased. The purchase price is typically financed 80% with debt provided by the creditor and the balance comes from equity funds provided by the lessor. The creditor provides long-term financing to the transaction secured by the property subject to the lease. Such long-term financing is non-recourse to the lessor and is not presented on our Consolidated Balance Sheets. In the event of default, the leased asset, and in some cases the lessee, secures the loan. As a lessor, Energy Holdings has ownership rights to the property and rents the property to the lessees for use in their business operations. For additional information, see Item 8. Financial Statements and Supplementary Data—Note 7. Long-Term Investments and Note 8. Financing Receivables.
In the event that collection of the minimum lease payments to be received by Energy Holdings is no longer reasonably assured, Energy Holdings may deem that a lessee has a high probability of defaulting on the lease obligation, and would consider the need to record an impairment of its investment. In the event the lease is ultimately rejected by the lessee in a Bankruptcy Court proceeding, the fair value of the underlying asset and the associated debt would be recorded on the Consolidated Balance Sheets instead of the net equity investment in the lease.
CRITICAL ACCOUNTING ESTIMATES
Under GAAP,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)
PSEG sponsors qualified and nonqualified pension plans and OPEB plans covering PSEG’s and its participating affiliates’ current and former employees who meet certain eligibility criteria. In late June 2019, PSEG approved a plan amendment to its qualified pension plan, effective July 1, 2019. The amendment involved the spin-off of predominantly active participants from the existing qualified pension plan (Pension Plan) into a new qualified pension plan (Pension Plan II). See Item 8. Note 14. Pension, Other Postretirement Benefits (OPEB) and Savings Plans for additional information. The market-related value of plan assets held for the qualified pension planand 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
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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.patterns, as well as projected health care costs for OPEB.
         
 Assumption 2017
 2016
 2015
 
 Discount Rate 3.73% 4.29% 4.54% 
 Expected Rate of Return on Plan Assets 7.80% 8.00% 8.00% 
         
Assumption202020192018
Pension
   Discount Rate2.61 %3.30 %4.41 %
   Expected Rate of Return on Plan Assets7.70 %7.80 %7.80 %
OPEB
   Discount Rate2.46 %3.20 %4.31 %
   Expected Rate of Return on Plan Assets7.70 %7.79 %7.80 %
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.
Based on the above assumptions, we have estimated a net periodic pension credit in 2018 of approximately $(36) million, or $(87) million, net of amounts capitalized.
We utilize a corridor approach that reduces the volatility of reported pension expense/income.costs/credits. The corridor requires differences between actuarial assumptions and plan results be deferred and amortized as part of expense/income.the costs/credits. This occurs only when the accumulated differences exceed 10% of the greater of the pension benefit obligation or the fair value of plan assets as of each year-end. TheFor 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 the active employees, which is approximately thirteenfourteen years.
Effect if Different Assumptions Used: As part of the business planning process, we have modeled future costs assuming a 7.80%7.70% expected rate of return and a 3.73%2.61% discount rate for 2018.2021 pension costs/credits and a 2.46% discount rate for 2021 OPEB costs/credits. Based upon these assumptions, we have estimated a net periodic pension credit in 2021 of approximately $82 million, or $142 million, net of amounts capitalized, and a net periodic OPEB credit in 2021 of approximately $96 million, or $100 million, net of amounts capitalized. Actual future pension expense/incomecosts/credits and funding levels

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will depend on future investment performance, changes in discount rates, market conditions, funding levels relative to our projected benefit obligation and accumulated benefit obligation and various other factors related to the populations participating in the pension plans. Actual future OPEB costs/credits will depend on future investment performance, changes in discount rates, market conditions, and various other factors.
The following chart reflects the sensitivities associated with a change in certain assumptions. The effects of the assumption changes shown below solely reflect the impact of that specific assumption.
           
   % Change 
Impact on Pension
Benefit Obligation as of December 31, 2017
 Increase to Pension Expense in 2018 
Increase to
Pension Expense, net of Amounts Capitalized
in 2018
 
 Assumption   Millions 
 Discount Rate (1)% $866
 $46
 $36
 
 Expected Rate of Return on Plan Assets (1)% N/A
 $57
 $57
 
           
% ChangeImpact on 
Benefit Obligation as of December 31, 2020		Increase to Costs in 2021Increase to
 Costs, net of Amounts Capitalized
in 2021
AssumptionMillions
Pension
   Discount Rate(1)%$987 $37 $26 
   Expected Rate of Return on Plan Assets(1)%N/A$62 $62 
OPEB
   Discount Rate(1)%$143 $17 $16 
   Expected Rate of Return on Plan Assets(1)%N/A$5 $5 
See Item 7A. Quantitative and Qualitative Disclosures About Market Risk for additional information.
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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 NYMEX,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. Financial Statements and Supplementary Data – Note 1. Organization, Basis of Presentation and Summary of Significant Accounting Policies, Note 16.18. Financial Risk Management Activities and Note 17.19. 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 suchwarrant assessment. Such events or changes in circumstances may be as a result of significant adverse changes in regulation, business climate, orcounterparty credit worthiness, market conditions, could potentially indicateor a determination that it is more-likely-than-not that an asset’sasset or asset group will be sold or retired before its estimated useful life, an asset group’s carrying amount may not be recoverable. recoverable or an asset’s probability of operating through its estimated remaining useful life changes.
Assumptions and Approach Used: In the event certain triggers exist indicating an asset/asset group may not be recoverable, an undiscounted cash flow test is performed to determine if an impairment exists. When the carrying value of a long-lived asset/asset group exceeds the undiscounted estimate of future cash flows associated with the asset/asset group, an impairment may exist to the extent that the fair value of the asset/asset group is less than its carrying amount.
For PSEG Power, cash flows for long-lived assets and asset groups are determined at the lowest level for which identifiable cash flows are largely independent of the cash flows of other assets and liabilities. The cash flows from the generation units are generally evaluated at a regional portfolio level (PJM, NYISO, ISO-NE), regardless of generation fuel type, along with cash flows generated from the customer supply and risk management activities, inclusive of cash flows from contracts, including those that are accounted for as derivatives and meet the normal purchases and normal sales scope exception. 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 (typically PSEG Power’s solar units and Kalaeloa). These tests require significant estimates and judgment when developing expected future cash flows. Significant inputs include, but are not limited to, forward power prices, fuel costs, dispatch rates, other operating and capital expenditures, and the cost of borrowing.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.

As a result of the strategic review of PSEG Power’s non-nuclear generating assets, and the launch in the fourth quarter of 2020 of an associated marketing process for their potential disposition, PSEG Power performed an impairment assessment of its PJM, NYISO and ISO-NE asset groupings, as well as for its solarassets, as of September 30, 2020 and December 31, 2020. The assessments included probability weightings assigned to undiscounted cash flow scenarios of retaining the assets through
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the end of their estimated useful lives and a successful disposition of the non-nuclear assets in 2021. Estimates of cash flows associated with a sale scenario were based on management’s expectations of the fair value of such assets. The probability weighted aggregation of undiscounted cash flows for each of the asset groupings expected to result from the use and potential disposition of the asset groups exceeded their carrying value at the above mentioned September 30, 2020 and December 31, 2020 assessment dates. As such, it demonstrated that no impairment exists for any of the asset groupings and they continue to remain classified as held for use as of December 31, 2020. Management expects that a change in the probability of a successful disposition based upon further progression in the marketing process, but prior to meeting all necessary held-for-sale classification criteria, would result in an impairment of the ISO-NE asset grouping, which would be material. Furthermore, a change to a held-for-sale classification from a held-for-use classification would result in an impairment of the PJM, NYISO and ISO-NE asset groupings, which would be material.
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 write-offs.
Lease Investments
Our Investments in Leases, included in Long-Term Investmentsaccelerated depreciation. For additional information on the potential impacts on our Consolidated Balance Sheets, are comprised of Lease Receivables (net of non-recourse debt),future financial statements that may be caused by a change in the estimated residual value of leased assets, and unearned and deferred income. A significant portion of the estimated residual value of leased assets is related to merchant power plants leased to other energy companies. Seeassumptions noted above, see Item 8. Financial Statements and Supplementary Data – Note 7. Long-Term Investments and Note 8. Financing Receivables.
Assumptions and Approach Used: 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. The estimated values are calculated by discounting the cash flows related to the leased assets after the lease term. For the merchant power plants, the estimated discounted cash flows are dependent upon various assumptions, including:
estimated forward power and capacity prices in the years after the lease,
related prices of fuel for the plants,
dispatch rates for the plants,
future capital expenditures required to maintain the plants,
future operation and maintenance expenses,
discount rates, and
the current estimated economic viability of the plants after the end of the base lease term.
A review of the residual valuations is performed at least annually for each plant subject to lease using specific assumptions tailored to each plant. Those valuations are compared to the recorded residual values to determine if an impairment is warranted.
Effect if Different Assumptions Used: A significant change to the assumptions, such as a large decrease in near-term power prices that affects the market’s view of long-term power prices, could result in an impairment of one or more of the residual values, but not necessarily to all of the residual values. However, if, because of changes in assumptions, all the residual values related to the merchant energy plants were deemed to be zero, we would recognize an after-tax charge to income of approximately $78 million.4. Early Plant Retirements/Asset Dispositions.
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 assetsRegulatory Assets or liabilitiesLiabilities 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 Operation and Maintenance.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 cost studies triennially unless new information necessitates more frequent updates. The most recent cost study was done in 2015.2018. When we revise any assumptions used to calculate fair values of existing AROs, we adjust the ARO

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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 93%95% or $852 million of PSEG Power’s total AROs as of December 31, 2017.2020. 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,
safe storage for
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•SAFSTOR alternative, which assumes the nuclear facility can be safely stored and subsequently decommissioned in a period of timewithin 60 years after retirement,operations,
•DECON alternative, which assumes decommissioning activities begin after operations, and
•recovery from the federal government of 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. For example, aHad the following assumptions been applied, our estimates of the approximate impacts on the Nuclear ARO as of December 31, 2020 are as follows:    
•A decrease of 1% in the discount rate would result in a $120$33 million increase in the Nuclear ARO as of December 31, 2017. ARO.
•An increase of 1% in the inflation rate would result in a $324$292 million increase in the Nuclear ARO as of December 31, 2017. Also, ifARO.
•If we didwere not assume that we would recover fromreimbursed by the federal government the costs incurred for spent nuclear fuel costs as prescribed under the Nuclear Waste Policy Act, the Nuclear ARO would increase by $550 million$399 million.
•If we would elect or be required to decommission under a DECON alternative at December 31, 2017. Salem and Hope Creek, the Nuclear ARO would increase by $710 million.
•If PSEG Power were to increase its early shutdown probability to 100% and retireretires Salem 1 and Hope Creek starting in 2021 (when the current capacity obligations for2022 and Salem and Hope Creek expire),2 in 2023, which is significantly earlier than the end of their current license periods, the Nuclear ARO would increase by $428$217 million. For additional information, see Item 8. Note 4. Early Plant Retirements/Asset Dispositions.
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 assetsRegulatory Assets and liabilitiesRegulatory 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. Financial Statements and Supplementary Data—Note 6.7. Regulatory Assets and Liabilities for a description of the amounts and nature of regulatory balance sheet amounts.


ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT
MARKET RISK
The risk inherent in our market-risk sensitive instruments and positions is the potential loss arising from adverse changes in commodity prices, equity security prices and interest rates as discussed in the Notes to Consolidated Financial Statements. It is our policy to use derivatives to manage risk consistent with business plans and prudent practices. We have a Risk Management

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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 servingload-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 
   Millions 
 Years Ended December 31, 2017 2016 
     
 95% Confidence Level, Loss could exceed VaR one day in 20 days     
 Period End $39
 $26
 
 Average for the Period $10
 $16
 
 High $39
 $32
 
 Low $5
 $10
 
       
 99.5% Confidence Level, Loss could exceed VaR one day in 200 days     
 Period End $60
 $40
 
 Average for the Period $15
 $25
 
 High $60
 $51
 
 Low $8
 $16
 
       
MTM VaR
Millions
Years Ended December 31,20202019
95% Confidence Level, Loss could exceed VaR one day in 20 days
Period End$16 $9 
Average for the Period$10 $12 
High$18 $35 
Low$5 $5 
99.5% Confidence Level, Loss could exceed VaR one day in 200 days
Period End$24 $14 
Average for the Period$16 $19 
High$29 $54 
Low$8 $8 
See Item 8. Financial Statements and Supplementary Data—Note 16.18. 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, 2017,2020, a hypothetical 10% increase in market interest rates would result in
$1 million of additional•no material impact on annual interest costs related to botheither the current andor the long-term portion of long-term debt, and
•a $370$357 million decrease in the fair value of debt, including a $16 million decrease at PSEG, a $309$328 million decrease at PSE&G and a $45$13 million decrease at PSEG Power.

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Debt and Equity Securities
We have $6.3$6.9 billion of 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,
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•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, 2017,2020, the portfolio included $1.1$1.4 billion of equity securities and $986 million$1.1 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, 2017,2020, a hypothetical 10% change in the equity market would impact the value of the equity securities in the NDT Fund by approximately $106$135 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 5.986.22 years and a yield of 2.72%1.14%. The portfolio’s value will appreciate or depreciate by the duration with a 1% change in interest rates. As of December 31, 2017,2020, a hypothetical 1% increase in interest rates would result in a decline in the market value for the fixed income portfolio of approximately $59$71 million.
Credit Risk
See Item 8. Financial Statements and Supplementary Data—Note 16. Financial Risk Management Activities for a discussion of credit risk and a discussion about Power’s and PSE&G’s credit risk.
Energy Holdings has credit risk related to its investments in leases, which totaled $85 million, net of deferred taxes of $480 million, as of December 31, 2017. These leveraged leases are concentrated in the U.S. energy industry. See Item 8. Financial Statements and Supplementary Data—Note 8. Financing Receivables for counterparties’ credit ratings and other information. The credit exposure to the lessees is partially mitigated through various credit enhancement mechanisms within the lease transactions. These credit enhancement features vary from lease to lease. Some of the leasing transactions include covenants that restrict the flow of dividends from the lessee to its parent, over-collateralization of the lessee with non-leased assets, and historical and forward cash flow coverage tests that prohibit discretionary capital expenditures and dividend payments to the parent/lessee if stated minimum coverages are not met. These covenants are designed to maintain cash reserves in the transaction entity for the benefit of the non-recourse lenders and the lessor/equity participants in the event of a temporary market downturn or degradation in operating performance of the leased assets.
In any lease transaction, in the event of a default, Energy Holdings would exercise its rights and attempt to seek recovery of its investment. The results of such efforts may not be known for a period of time. A bankruptcy of a lessee and failure to recover adequate value could lead to a foreclosure of the lease. Under a worst-case scenario, if a foreclosure were to occur, Energy Holdings would record a pre-tax write-off up to its outstanding gross investment in these facilities. Also, in the event of a potential foreclosure, the net tax benefits generated by Energy Holdings’ portfolio of investments could be materially reduced in the period in which gains associated with the potential forgiveness of debt at these projects occurs. The amount and timing of any potential reduction in net tax benefits is dependent upon a number of factors including, but not limited to, the time of a potential foreclosure, the amount of lease debt outstanding, any cash trapped at the projects and negotiations during such potential foreclosure process. The potential loss of earnings, impairment and/or tax payments could have a material impact to our financial position, results of operations and net cash flows. 

ITEM 8.    FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
This combined Form 10-K is separately filed by PSEG, PSE&G and PSEG Power. Information contained herein relating to any individual company is filed by such company on its own behalf. PSE&G and PSEG Power each make representations only as to itself and make no representations as to any other company.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of
Public Service Enterprise Group Incorporated
Newark, New Jersey
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, 20172020 and 2016,2019, 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, 2017,2020, 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, 20172020 and 2016,2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017,2020, 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”)(PCAOB), the Company's internal control over financial reporting as of December 31, 2017,2020, based on criteria established inInternal Control -— Integrated Framework (2013)issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated February 26, 2018,2021, 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.

Early Plant Retirements - Nuclear — 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 in New Jersey and has recorded associated asset retirement obligations (ARO) for their eventual decommissioning. In April 2019, the New Jersey Board of Public Utilities (BPU) awarded Zero Emission Certificates (ZEC) to PSEG Power’s Salem 1, Salem 2 and Hope Creek nuclear plants for an initial period of approximately three years through May 2022. The initial ZEC award has been appealed by the New Jersey Rate Counsel and PSEG Power cannot predict the outcome of this matter. In October, 2020, PSEG Power filed its application for the second eligibility period beginning in June 2022.







In the event that (i) the ZEC program is overturned or is otherwise materially adversely modified through legal process; (ii) the amount of ZEC payments that may be awarded or other terms and conditions of the second ZEC eligibility period proposed by the BPU in its final decision differ from those of the current ZEC period; or (iii) any of the Salem 1, Salem 2 and Hope Creek plants is not awarded ZEC payments by the BPU and does not otherwise experience a material financial change, PSEG Power has disclosed that it will take all necessary steps to cease to operate these nuclear plants. This would result in material charges
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associated with accelerated depreciation and amortization, impairment charges, and accelerated asset retirement costs, among other costs.
We identified the potential early retirement of the nuclear plants as a critical audit matter because of the significant estimates and assumptions management made in determining the useful lives of the nuclear plants and in evaluating the recorded investments in the nuclear plants for potential impairment. Further, management’s estimates used in recording the ARO included a number of assumptions, including the timing of cash flows associated with the eventual decommissioning of the nuclear plants following the retirement of the assets. Auditing each of these assumptions required a high degree of auditor judgment.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the potential early retirement of the nuclear plants and the related impact on the recorded investments in the nuclear plants and the related ARO included the following, among others:
•We tested the effectiveness of controls over the evaluation of potential impairment indicators, including management’s consideration of legal and regulatory matters related to ZECs.
•We tested the effectiveness of controls over the evaluation of retirement date assumptions used in the calculation of the ARO, including the probability weighting of the various cash flow scenarios.
•We evaluated management’s judgments over the probability of early retirement of the nuclear plants and impairment triggers including considerations of regulatory matters for the second ZEC eligibility period.
•We evaluated management’s assumptions over the weighted-probability of early retirement of the nuclear plants used in calculating the recorded nuclear ARO balance.
•We requested and received a written response from internal counsel and external legal firms representing PSEG and evaluated the legal conclusions for consistency with those used in management’s accounting judgments and disclosures.
•We obtained written representations from management regarding their intent to cease to operate the nuclear plants in the event that certain legal, regulatory, and economic matters are not favorably resolved.
•We evaluated the related disclosures for consistency with our understanding.
Asset Dispositions - Potential Sale of Non-Nuclear Assets – Impairment Tests — Refer to Note 4 to the financial statements
Critical Audit Matter Description
In July 2020, PSEG Power announced that it is exploring strategic alternatives for its non-nuclear generating fleet, which includes more than 6,750 MW of fossil generation located in New Jersey, Connecticut, New York and Maryland. As a result, PSEG Power performed impairment tests for its portfolio of assets in the PJM, NYISO and NEPOOL regions. The assessments included probability weightings assigned to undiscounted cash flow scenarios of retaining the assets through their estimated useful lives and a potential disposition of the assets. As of December 31, 2020, the estimated undiscounted future cash flows of each of the asset groups exceeded the carrying amount and no impairment was identified.
We identified the impairment tests over the PJM, NYISO and NEPOOL asset groupings as a critical audit matter because of the significant management judgements and estimates related to asset grouping conclusions, the probability weighting of the outcomes of various scenarios, and the significant inputs utilized in the impairment test to determine the estimated undiscounted cash flows. Those inputs include estimated forward power prices, fuel costs and dispatch rates as well as estimates of fair value to be received upon any disposition of assets. Auditing these estimates and assumptions required a high degree of auditor judgment and the involvement of our fair value specialists.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the impairment tests over the PJM, NYISO and NEPOOL asset groupings included the following, among others:
•We tested the effectiveness of controls over management’s impairment tests including considerations of asset groupings, the significant inputs utilized to determine estimated undiscounted cash flows, and the weighted probabilities assigned to the outcome of various scenarios.
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•We evaluated management’s conclusions regarding the asset groupings utilized for the purposes of the impairment tests.
•With the assistance of our fair value specialists, we evaluated the significant inputs 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 evaluated management’s assumptions related to the weighted probabilities assigned to the outcome of various scenarios.
•We evaluated the related disclosures for consistency with our understanding.
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 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 related disclosures for consistency with our understanding.
Commitments and Contingent Liabilities - Passaic River Environmental Liability—Refer to Note 15 to the financial statements
Critical Audit Matter Description
As described in Note 15, the U.S. Environmental Protection Agency (EPA) has designated a 17-mile stretch of the lower Passaic River (Lower Passaic River Study Area (LPRSA)) in New Jersey as a “superfund” site requiring environmental remediation and has identified certain Potentially Responsible Parties (PRPs), including PSEG. The EPA has released a Record of Decision (ROD) for the LPRSA’s lower 8.3 miles that requires the removal of sediments at an estimated cost of $2.3 billion
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(ROD Remedy). An EPA-commenced process to allocate the associated costs to the PRPs is underway, and PSEG cannot predict the outcome. Additionally, one of the PRPs has filed suit against PSEG and others seeking cost recovery and contribution under the Federal Comprehensive Environmental Response, Compensation and Liability Act of 1980, but has not quantified alleged damages. The litigation is ongoing and PSEG cannot predict the outcome. As of December 31, 2020, PSEG recorded an environmental liability of $65 million for its estimated share of the remediation of the environmental contamination, a portion of which has been deferred as a regulatory asset based on PSEG’s assessment that PSE&G will recover such costs in future rates.
The outcome of this matter is uncertain, and PSEG cannot predict this matter’s ultimate impact on its financial statements. It is possible that PSEG will record additional costs beyond what it has accrued, and that such costs could be material, but PSEG cannot at the current time estimate the amount or range of any additional costs.
We identified the accounting for the Passaic River environmental liability as a critical audit matter due to the uncertainties inherent in estimating PSEG’s liability. Auditing PSEG’s estimated share of the remediation cost, the environmental liability recorded, and the evaluation of future recovery of the regulatory asset recorded required a high degree of auditor judgment and the involvement of our environmental specialists.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the Passaic River environmental liability included the following, among others:
•We tested the effectiveness of controls over the Passaic River environmental liability, including those over the evaluation of recent events and changes in circumstances that have or may give rise to a change in PSEG’s estimated share of the total remediation costs.
•We tested the effectiveness of controls over the Passaic River regulatory asset, including controls over the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering the Passaic River regulatory asset in future rates.
•With the assistance of our environmental specialists, we evaluated publicly available information regarding the status of the Passaic River superfund site, including planned remediation techniques and associated estimated costs, and compared this to information used in management’s estimate of the environmental liability.
•We evaluated the assumptions used by management to estimate PSEG’s share of the environmental obligation, including consideration of publicly available information.
•We requested and received a written response from internal counsel and external legal firms representing PSEG and evaluated the legal conclusions for consistency with those used in management’s accounting judgments and disclosures.
•We evaluated management’s analysis over the assertion that the Passaic River regulatory asset is probable of recovery.
•We evaluated the related disclosures for consistency with our understanding.





/s/ DELOITTE & TOUCHE LLP
Parsippany, New Jersey
February 26, 20182021


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

7467
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Sole Stockholder of
Public Service Electric and Gas Company
Newark, New Jersey


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, 20172020 and 2016, and2019, 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, 2017, and2020, 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, 20172020 and 2016,2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017,2020, 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”)(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 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.

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

Critical Audit Matter Description








PSE&G’s electric and gas transmission and distribution businesses are regulated by the Board of Public Utilities (BPU) and Federal Energy Regulatory Commission. Management believes that PSE&G’s transmission and distribution businesses continue to meet the accounting requirements for rate-regulated entities, and PSE&G’s financial statements reflect the economic effects of cost-based rate regulation. Through the rate-making process, PSE&G’s rates to customers also include the recovery of income tax expense associated with PSE&G’s electric and gas distribution and electric transmission operations. PSE&G has recorded regulatory liabilities for excess accumulated deferred income taxes (ADIT) which will be refunded to customers in future periods. PSE&G’s most recent electric and gas distribution base rate case, concluded in 2018, established the Tax Adjustment Credit (TAC) that provides for the refund of these excess ADIT regulatory liabilities as well as the flow through to customers of historical and current accumulated deferred income taxes for tax-deductible repairs. The flow through of the current tax benefits results in lower revenues and lower income tax expense, as well as the recognition of a regulatory asset as management believes it is probable that the accumulated tax benefits treated as a flow-through item to PSE&G customers will be recovered from customers in the future.
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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 related disclosures for consistency with our understanding.
Commitments and Contingent Liabilities - Passaic River Environmental Liability — Refer to Note 15 to the financial statements
Critical Audit Matter Description
As described in Note 15, the U.S. Environmental Protection Agency (EPA) has designated a 17-mile stretch of the lower Passaic River (Lower Passaic River Study Area (LPRSA)) in New Jersey as a “superfund” site requiring environmental remediation and has identified certain Potentially Responsible Parties (PRPs), including PSE&G. The EPA has released a Record of Decision (ROD) for the LPRSA’s lower 8.3 miles that requires the removal of sediments at an estimated cost of $2.3 billion (ROD Remedy). An EPA-commenced process to allocate the associated costs to the PRPs is underway, and PSE&G cannot predict the outcome. Additionally, one of the PRPs has filed suit against PSE&G and others seeking cost recovery and contribution under the Federal Comprehensive Environmental Response, Compensation and Liability Act of 1980, but has not quantified alleged damages. The litigation is ongoing and PSE&G cannot predict the outcome. As of December 31, 2020, PSE&G recorded an environmental liability of $52 million for its estimated share of the remediation of the environmental contamination, and a corresponding regulatory asset based on PSE&G’s assessment that it will recover such costs in future rates.
The outcome of this matter is uncertain, and PSE&G cannot predict this matter’s ultimate impact on its financial statements. It is possible that PSE&G will record additional costs beyond what it has accrued, and that such costs could be material, but PSE&G cannot at the current time estimate the amount or range of any additional costs.
We identified the accounting for the Passaic River environmental liability as a critical audit matter due to the uncertainties inherent in estimating PSE&G’s liability. Auditing PSE&G’s estimated share of the remediation cost, the environmental liability recorded, and the evaluation of future recovery of the regulatory asset recorded required a high degree of auditor judgment and the involvement of our environmental specialists.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the Passaic River environmental liability included the following, among others:
• We tested the effectiveness of controls over the Passaic River environmental liability, including those over the evaluation of recent events and changes in circumstances that have or may give rise to a change in PSE&G’s estimated share of the total remediation costs.
• We tested the effectiveness of controls over the Passaic River regulatory asset, including controls over the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering the Passaic River regulatory asset in future rates.
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• With the assistance of our environmental specialists, we evaluated publicly available information regarding the status of the Passaic River superfund site, including planned remediation techniques and associated estimated costs, and compared this to information used in management’s estimate of the environmental liability.
• We evaluated the assumptions used by management to estimate PSE&G’s share of the environmental obligation, including consideration of publicly available information.
• We requested and received a written response from external legal firms representing PSE&G and evaluated the legal conclusions for consistency with those used in management’s accounting judgments and disclosures.
• We evaluated management’s analysis over the assertion that the Passaic River regulatory asset is probable of recovery.
• We evaluated the related disclosures for consistency with our understanding.








/s/ DELOITTE & TOUCHE LLP
Parsippany, New Jersey
February 26, 20182021


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

7570
TableTable of Contents




REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Sole Member of
PSEG Power LLC
Newark, New Jersey


Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of PSEG Power LLC and subsidiaries (the “Company”) or PSEG Power) as of December 31, 20172020 and 2016,2019, the related consolidated statements of operations, comprehensive income, member’s equity, and cash flows, for each of the three years in the period ended December 31, 2017,2020, the related notes and the consolidated financial statement schedule listed in the Index at Item 15(B)(c) (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, 20172020 and 2016,2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017,2020, 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”)(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 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.

Early Plant Retirements - Nuclear - Refer to Notes 4 and 13 to the financial statements

Critical Audit Matter Description

PSEG Power owns and operates nuclear plants in New Jersey and has recorded associated asset retirement obligations (ARO) for their eventual decommissioning. In April 2019, the New Jersey Board of Public Utilities (BPU) awarded Zero Emission Certificates (ZEC) to PSEG Power’s Salem 1, Salem 2 and Hope Creek nuclear plants for an initial period of approximately three years through May 2022. The initial ZEC award has been appealed by the New Jersey Rate Counsel and PSEG Power cannot predict the outcome of this matter. In October 2020, PSEG Power filed its application for the second eligibility period beginning in June 2022.








In the event that (i) the ZEC program is overturned or is otherwise materially adversely modified through legal process; (ii) the amount of ZEC payments that may be awarded or other terms and conditions of the second ZEC eligibility period proposed by the BPU in its final decision differ from those of the current ZEC period; or (iii) any of the Salem 1, Salem 2 and Hope Creek plants is not awarded ZEC payments by the BPU and does not otherwise experience a material financial change, PSEG Power has disclosed that it will take all necessary steps to cease to operate these nuclear plants. This would result in material charges associated with accelerated depreciation and amortization, impairment charges, and accelerated asset retirement costs, among other costs.
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We identified the potential early retirement of the nuclear plants as a critical audit matter because of the significant estimates and assumptions management made in determining the useful lives of the nuclear plants and in evaluating the recorded investments in the nuclear plants for potential impairment. Further, management’s estimates used in recording the ARO included a number of assumptions, including the timing of cash flows associated with the eventual decommissioning of the nuclear plants following the retirement of the assets. Auditing each of these assumptions required a high degree of auditor judgment.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the potential early retirement of the nuclear plants and the related impact on the recorded investments in the nuclear plants and the related ARO included the following, among others:
•We tested the effectiveness of controls over the evaluation of potential impairment indicators, including management’s consideration of legal and regulatory matters related to ZECs.
•We tested the effectiveness of controls over the evaluation of retirement date assumptions used in the calculation of the ARO, including the probability weighting of the various cash flow scenarios.
•We evaluated management’s judgments over the probability of early retirement of the nuclear plants and impairment triggers including considerations of regulatory matters for the second ZEC eligibility period.
•We evaluated management’s assumptions over the weighted-probability of early retirement of the nuclear plants used in calculating the recorded nuclear ARO balance.
•We requested and received written response from internal counsel and external legal firms representing PSEG Power and evaluated the legal conclusions for consistency with those used in management’s accounting judgments and disclosures.
•We obtained written representations from management regarding their intent to cease to operate the nuclear plants in the event that certain legal, regulatory, and economic matters are not favorably resolved.
•We evaluated the related disclosures for consistency with our understanding.
Asset Dispositions – Potential Sale of Non-Nuclear Assets – Impairment Tests — Refer to Note 4 to the financial statements
Critical Audit Matter Description
In July 2020, PSEG Power announced that it is exploring strategic alternatives for its non-nuclear generating fleet, which includes more than 6,750 MW of fossil generation located in New Jersey, Connecticut, New York and Maryland. As a result, PSEG Power performed impairment tests for its portfolio of assets in the PJM, NYISO and NEPOOL regions. The assessments included probability weightings assigned to undiscounted cash flow scenarios of retaining the assets through their estimated useful lives and a potential disposition of the assets. As of December 31, 2020, the estimated undiscounted future cash flows of each of the asset groups exceeded the carrying amount and no impairment was identified.
We identified the impairment tests over the PJM, NYISO and NEPOOL asset groupings as a critical audit matter because of the significant management judgements and estimates related to asset grouping conclusions, the probability weighting of the outcomes of various scenarios, and the significant inputs utilized in the impairment test to determine the estimated undiscounted cash flows. Those inputs include estimated forward power prices, fuel costs and dispatch rates as well as estimates of fair value to be received upon any disposition of assets. Auditing these estimates and assumptions required a high degree of auditor judgment and the involvement of our fair value specialists.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the impairment tests over the PJM, NYISO and NEPOOL asset groupings included the following, among others:
•We tested the effectiveness of controls over management’s impairment tests including considerations of asset groupings, the significant inputs utilized to determine estimated undiscounted cash flows, and the weighted probabilities assigned to the outcome of various scenarios.
•We evaluated management’s conclusions regarding the asset groupings utilized for the purposes of the impairment tests.
•With the assistance of our fair value specialists, we evaluated the significant inputs utilized within management’s impairment tests including forward power prices, fuel costs, dispatch rates and estimates of the fair value to be
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received upon any disposition of assets.
•We evaluated management’s assumptions related to the weighted probabilities assigned to the outcome of various scenarios.
•We evaluated the related disclosures for consistency with our understanding.
Commitments and Contingent Liabilities - Passaic River Environmental Liability — Refer to Note 15 to the financial statements
Critical Audit Matter Description
As described in Note 15, the U.S. Environmental Protection Agency (EPA) has designated a 17-mile stretch of the lower Passaic River (Lower Passaic River Study Area (LPRSA)) in New Jersey as a “superfund” site requiring environmental remediation and has identified certain potentially responsible parties (PRPs), including PSEG Power. The EPA has released a Record of Decision (ROD) for the LPRSA’s lower 8.3 miles that requires the removal of sediments at an estimated cost of $2.3 billion (ROD Remedy). An EPA-commenced process to allocate the associated costs to the PRPs is underway, and PSEG Power cannot predict the outcome. Additionally, one of the PRPs has filed suit against PSEG Power and others seeking cost recovery and contribution under the Federal Comprehensive Environmental Response, Compensation and Liability Act of 1980, but has not quantified alleged damages. The litigation is ongoing and PSEG Power cannot predict the outcome. As of December 31, 2020, PSEG Power recorded an environmental liability of $13 million for its estimated share of the remediation of the environmental contamination.
The outcome of this matter is uncertain, and PSEG Power cannot predict this matter’s ultimate impact on its financial statements. It is possible that PSEG Power will record additional costs beyond what it has accrued, and that such costs could be material, but PSEG Power cannot at the current time estimate the amount or range of any additional costs.
We identified the accounting for the Passaic River environmental liability as a critical audit matter due to the uncertainties inherent in estimating PSEG Power’s liability. Auditing PSEG Power’s estimated share of the remediation cost and the environmental liability recorded required a high degree of auditor judgment and the involvement of our environmental specialists.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the Passaic River environmental liability included the following, among others:
•We tested the effectiveness of controls over the Passaic River environmental liability, including those over the evaluation of recent events and changes in circumstances that have or may give rise to a change in PSEG Power’s estimated share of the total remediation costs.
•With the assistance of our environmental specialists, we evaluated publicly available information regarding the status of the Passaic River superfund site, including planned remediation techniques and associated estimated costs, and compared this to information used in management’s estimate of the environmental liability.
•We evaluated the assumptions used by management to estimate PSEG Power’s share of the environmental obligation, including consideration of publicly available information.
•We requested and received a written response from internal counsel and external legal firms representing PSEG Power and evaluated the legal conclusions for consistency with those used in management’s accounting judgments and disclosures.
•We evaluated the related disclosures for consistency with our understanding.
/s/ DELOITTE & TOUCHE LLP
Parsippany, New Jersey
February 26, 20182021


We have served as the Company's auditor since 2000.

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PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONSOLIDATED STATEMENTS OF OPERATIONS
Millions, except per share data
Years Ended December 31,
 202020192018
OPERATING REVENUES$9,603 $10,076 $9,696 
OPERATING EXPENSES
Energy Costs3,056 3,372 3,225 
Operation and Maintenance3,115 3,111 3,069 
Depreciation and Amortization1,285 1,248 1,158 
(Gain) Loss on Asset Dispositions(123)402 (54)
Total Operating Expenses7,333 8,133 7,398 
OPERATING INCOME2,270 1,943 2,298 
Income from Equity Method Investments14 14 15 
Net Gains (Losses) on Trust Investments253 260 (143)
Other Income (Deductions)115 125 85 
Non-Operating Pension and OPEB Credits (Costs)249 177 76 
Interest Expense(600)(569)(476)
INCOME BEFORE INCOME TAXES2,301 1,950 1,855 
Income Tax Benefit (Expense)(396)(257)(417)
NET INCOME$1,905 $1,693 $1,438 
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:
BASIC504 504 504 
DILUTED507 507 507 
NET INCOME PER SHARE:
BASIC$3.78 $3.35 $2.85 
DILUTED$3.76 $3.33 $2.83 
         
   Years Ended December 31, 
   2017 2016 2015 
 OPERATING REVENUES $9,084
 $9,061
 $10,415
 
 OPERATING EXPENSES       
 Energy Costs 2,800
 3,001
 3,261
 
 Operation and Maintenance 2,869
 3,008
 2,978
 
 Depreciation and Amortization 1,986
 1,476
 1,214
 
 Total Operating Expenses 7,655
 7,485
 7,453
 
 OPERATING INCOME 1,429
 1,576
 2,962
 
 Income from Equity Method Investments 14
 11
 12
 
 Other Income 319
 191
 254
 
 Other Deductions (91) (67) (102) 
 Other-Than-Temporary Impairments (12) (28) (53) 
 Interest Expense (391) (385) (393) 
 INCOME BEFORE INCOME TAXES 1,268
 1,298
 2,680
 
 Income Tax Benefit (Expense) 306
 (411) (1,001) 
 NET INCOME $1,574
 $887
 $1,679
 
 WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:       
 BASIC 505
 505
 505
 
 DILUTED 507
 508
 508
 
 NET INCOME PER SHARE:       
 BASIC $3.12
 $1.76
 $3.32
 
 DILUTED $3.10
 $1.75
 $3.30
 
         

See Notes to Consolidated Financial Statements.



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PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Millions


 
         
  Years Ended December 31, 
   2017 2016 2015 
 NET INCOME $1,574
 $887
 $1,679
 
 Other Comprehensive Income (Loss), net of tax       
 Unrealized Gains (Losses) on Available-for-Sale Securities, net of tax (expense) benefit of $(37), $(41) and $34 for the years ended 2017, 2016 and 2015, respectively 44
 42
 (27) 
 Unrealized Gains (Losses) on Cash Flow Hedges, net of tax (expense) benefit of $1, $(1), and $7 for the years ended 2017, 2016 and 2015, respectively (2) 2
 (10) 
 Pension/Other Postretirement Benefit Costs (OPEB) adjustment, net of tax (expense) benefit of $(4), $8 and $(18) for the years ended 2017, 2016 and 2015, respectively (8) (12) 25
 
 Other Comprehensive Income (Loss), net of tax 34
 32
 (12) 
 COMPREHENSIVE INCOME $1,608
 $919
 $1,667
 
         
 Years Ended December 31,
 202020192018
NET INCOME$1,905 $1,693 $1,438 
Other Comprehensive Income (Loss), net of tax
Unrealized Gains (Losses) on Available-for-Sale Securities, net of tax (expense) benefit of $(16), $(26) and $11 for the years ended 2020, 2019 and 2018, respectively25 41 (17)
Unrealized Gains (Losses) on Cash Flow Hedges, net of tax (expense) benefit of $(2), $6 and $1 for the years ended 2020, 2019 and 2018, respectively6 (14)(1)
Pension/OPEB adjustment, net of tax (expense) benefit of $18, $18 and $(18) for the years ended 2020, 2019 and 2018, respectively(46)(58)46 
Other Comprehensive Income (Loss), net of tax(15)(31)28 
COMPREHENSIVE INCOME$1,890 $1,662 $1,466 
See Notes to Consolidated Financial Statements.







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PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONSOLIDATED BALANCE SHEETS
Millions
December 31,
20202019
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents$543 $147 
Accounts Receivable, net of allowance of $196 in 2020 and $60 in 20191,410 1,313 
Tax Receivable63 21 
Unbilled Revenues, net of allowance of $10 in 2020229 239 
Fuel277 310 
Materials and Supplies, net601 587 
Prepayments51 79 
Derivative Contracts60 113 
Regulatory Assets369 351 
Assets Held for Sale0 30 
Other27 41 
Total Current Assets3,630 3,231 
PROPERTY, PLANT AND EQUIPMENT48,569 45,944 
Less: Accumulated Depreciation and Amortization(10,984)(10,100)
Net Property, Plant and Equipment37,585 35,844 
NONCURRENT ASSETS
Regulatory Assets3,872 3,677 
Operating Lease Right-of-Use Assets262 282 
Long-Term Investments536 812 
Nuclear Decommissioning Trust (NDT) Fund2,501 2,216 
Long-Term Tax Receivable0 150 
Long-Term Receivable of Variable Interest Entity945 813 
Rabbi Trust Fund266 246 
Other Intangibles158 149 
Derivative Contracts9 24 
Other286 286 
Total Noncurrent Assets8,835 8,655 
TOTAL ASSETS$50,050 $47,730 
      
  December 31, 
  2017 2016 
 ASSETS 
 CURRENT ASSETS    
 Cash and Cash Equivalents$313
 $423
 
 Accounts Receivable, net of allowances of $59 in 2017 and $68 in 20161,348
 1,161
 
 Tax Receivable127
 78
 
 Unbilled Revenues296
 260
 
 Fuel289
 326
 
 Materials and Supplies, net577
 561
 
 Prepayments118
 76
 
 Derivative Contracts29
 163
 
 Regulatory Assets211
 199
 
 Other4
 7
 
 Total Current Assets3,312
 3,254
 
 PROPERTY, PLANT AND EQUIPMENT41,231
 39,337
 
 Less: Accumulated Depreciation and Amortization(9,434) (10,051) 
 Net Property, Plant and Equipment31,797
 29,286
 
 NONCURRENT ASSETS    
 Regulatory Assets3,222
 3,319
 
 Long-Term Investments932
 1,050
 
 Nuclear Decommissioning Trust (NDT) Fund2,133
 1,859
 
 Long-Term Tax Receivable—
 104
 
 Long-Term Receivable of VIEs686
 589
 
 Other Special Funds231
 217
 
 Goodwill16
 16
 
 Other Intangibles114
 98
 
 Derivative Contracts7
 24
 
 Other266
 254
 
 Total Noncurrent Assets7,607
 7,530
 
 TOTAL ASSETS$42,716
 $40,070
 
      
See Notes to Consolidated Financial Statements.



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PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONSOLIDATED BALANCE SHEETS
Millions
 
      
  December 31, 
  2017 2016 
 LIABILITIES AND CAPITALIZATION 
 CURRENT LIABILITIES
 
 
 Long-Term Debt Due Within One Year$1,000
 $500
 
 Commercial Paper and Loans542
 388
 
 Accounts Payable1,694
 1,459
 
 Derivative Contracts16
 13
 
 Accrued Interest103
 97
 
 Accrued Taxes48
 31
 
 Clean Energy Program128
 142
 
 Obligation to Return Cash Collateral129
 132
 
 Regulatory Liabilities47
 88
 
 Other461
 426
 
 Total Current Liabilities4,168
 3,276
 
 NONCURRENT LIABILITIES    
 Deferred Income Taxes and Investment Tax Credits (ITC)5,240
 8,658
 
 Regulatory Liabilities2,948
 118
 
 Asset Retirement Obligations1,024
 726
 
 Other Postretirement Benefit (OPEB) Costs1,455
 1,324
 
 OPEB Costs of Servco542
 452
 
 Accrued Pension Costs537
 568
 
 Accrued Pension Costs of Servco129
 128
 
 Environmental Costs357
 401
 
 Derivative Contracts5
 3
 
 Long-Term Accrued Taxes175
 180
 
 Other221
 211
 
 Total Noncurrent Liabilities12,633
 12,769
 
 COMMITMENTS AND CONTINGENT LIABILITIES (See Note 13)

 
 
 CAPITALIZATION    
 
LONG-TERM DEBT

12,068
 10,895
 
 STOCKHOLDERS’ EQUITY    
 Common Stock, no par, authorized 1,000 shares; issued, 2017 and 2016— 534 shares4,961
 4,936
 
 Treasury Stock, at cost, 2017 and 2016—29 shares(763) (717) 
 Retained Earnings9,878
 9,174
 
 Accumulated Other Comprehensive Loss(229) (263) 
 Total Stockholders’ Equity13,847
 13,130
 
 Total Capitalization25,915
 24,025
 
 TOTAL LIABILITIES AND CAPITALIZATION$42,716
 $40,070
 
      
December 31,
20202019
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES
Long-Term Debt Due Within One Year$1,684 $1,365 
Commercial Paper and Loans1,063 1,115 
Accounts Payable1,332 1,358 
Derivative Contracts21 36 
Accrued Interest126 116 
Accrued Taxes124 41 
Clean Energy Program143 143 
Obligation to Return Cash Collateral98 119 
Regulatory Liabilities294 234 
Other637 520 
Total Current Liabilities5,522 5,047 
NONCURRENT LIABILITIES
Deferred Income Taxes and Investment Tax Credits (ITC)6,502 6,256 
Regulatory Liabilities2,707 3,002 
Operating Leases252 273 
Asset Retirement Obligations1,212 1,087 
Other Postretirement Benefit (OPEB) Costs730 734 
OPEB Costs of Servco699 626 
Accrued Pension Costs1,128 952 
Accrued Pension Costs of Servco226 171 
Environmental Costs286 349 
Derivative Contracts4 1 
Long-Term Accrued Taxes88 182 
Other214 218 
Total Noncurrent Liabilities14,048 13,851 
COMMITMENTS AND CONTINGENT LIABILITIES (See Note 15)00
CAPITALIZATION
LONG-TERM DEBT
14,496 13,743 
STOCKHOLDERS’ EQUITY
Common Stock, no par, authorized 1,000 shares; issued, 2020 and 2019—534 shares5,031 5,003 
Treasury Stock, at cost, 2020 and 2019—30 shares(861)(831)
Retained Earnings12,318 11,406 
Accumulated Other Comprehensive Loss(504)(489)
Total Stockholders’ Equity15,984 15,089 
Total Capitalization30,480 28,832 
TOTAL LIABILITIES AND CAPITALIZATION$50,050 $47,730 
See Notes to Consolidated Financial Statements.

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PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONSOLIDATED STATEMENTS OF CASH FLOWS
Millions
         
   Years Ended December 31, 
   2017 2016 2015 
 CASH FLOWS FROM OPERATING ACTIVITIES       
 Net Income $1,574
 $887
 $1,679
 
 Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:       
    Depreciation and Amortization 1,986
 1,476
 1,214
 
    Amortization of Nuclear Fuel 199
 203
 213
 
    Emission Allowances and Renewable Energy Credit (REC) Compliance Accrual 103
 109
 104
 
    Impairment Costs for Early Plant Retirements —
 102
 —
 
    Provision for Deferred Income Taxes (Other than Leases) and ITC (167) 474
 685
 
    Non-Cash Employee Benefit Plan Costs 89
 127
 161
 
    Leveraged Lease Income, Adjusted for Rents Received and Deferred Taxes (159) (6) 26
 
    Net (Gain) Loss on Lease Investments 48
 92
 —
 
 Net Realized and Unrealized (Gains) Losses on Energy Contracts and Other Derivatives 188
 183
 (143) 
    Net Change in Regulatory Assets and Liabilities (188) (138) (48) 
    Cost of Removal (107) (131) (120) 
    Net Realized (Gains) Losses and (Income) Expense from NDT Fund (156) (26) (38) 
    Net Change in Certain Current Assets and Liabilities       
         Tax Receivable 65
 303
 (94) 
         Accrued Taxes 16
 3
 (91) 
         Margin Deposit (90) (76) 122
 
         Other Current Assets and Liabilities (70) (180) 288
 
    Employee Benefit Plan Funding and Related Payments (81) (103) (109) 
    Other 11
 12
 70
 
   Net Cash Provided By (Used In) Operating Activities 3,261
 3,311
 3,919
 
 CASH FLOWS FROM INVESTING ACTIVITIES       
 Additions to Property, Plant and Equipment (4,190) (4,199) (3,863) 
 Purchase of Emissions Allowances and RECs (117) (99) (106) 
 Proceeds from Sales of Available-for-Sale Securities 2,319
 824
 1,501
 
 Investments in Available-for-Sale Securities (2,340) (856) (1,552) 
 Other 72
 82
 78
 
   Net Cash Provided By (Used In) Investing Activities (4,256) (4,248) (3,942) 
 CASH FLOWS FROM FINANCING ACTIVITIES       
 Net Change in Commercial Paper and Loans 154
 24
 364
 
 Issuance of Long-Term Debt 2,175
 2,675
 1,350
 
 Redemption of Long-Term Debt (500) (824) (600) 
 Redemption of Securitization Debt —
 —
 (259) 
 Cash Dividends Paid on Common Stock (870) (830) (789) 
 Other (74) (79) (51) 
   Net Cash Provided By (Used In) Financing Activities 885
 966
 15
 
 Net Increase (Decrease) in Cash and Cash Equivalents (110) 29
 (8) 
 Cash and Cash Equivalents at Beginning of Period 423
 394
 402
 
 Cash and Cash Equivalents at End of Period $313
 $423
 $394
 
 Supplemental Disclosure of Cash Flow Information:       
 Income Taxes Paid (Received) $(8) $(245) $447
 
 Interest Paid, Net of Amounts Capitalized $377
 $365
 $381
 
 Accrued Property, Plant and Equipment Expenditures $722
 $664
 $510
 
         
Years Ended December 31,
202020192018
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income$1,905 $1,693 $1,438 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization1,285 1,248 1,158 
Amortization of Nuclear Fuel184 178 187 
(Gain) Loss on Asset Dispositions(123)402 (54)
Emission Allowances and Renewable Energy Credit (REC) Compliance Accrual151 108 97 
Provision for Deferred Income Taxes (Other than Leases) and ITC139 180 568 
Non-Cash Employee Benefit Plan (Credits) Costs(105)(48)70 
Leveraged Lease (Income), (Gains) and Losses, Adjusted for Rents Received and Deferred Taxes(135)18 (144)
Net Realized and Unrealized (Gains) Losses on Energy Contracts and Other Derivatives80 (290)116 
Cost of Removal(106)(108)(160)
Net Change in Regulatory Assets and Liabilities(101)25 (153)
Net (Gains) Losses and (Income) Expense from NDT Fund(278)(296)98 
Net Change in Certain Current Assets and Liabilities:
      Tax Receivable107 77 17 
      Accrued Taxes124 (9)(69)
      Cash Collateral(10)349 (247)
      Other Current Assets and Liabilities73 (145)70 
Employee Benefit Plan Funding and Related Payments(18)(39)(101)
Other(70)36 22 
  Net Cash Provided By (Used In) Operating Activities3,102 3,379 2,913 
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment(2,923)(3,166)(3,912)
Purchase of Emissions Allowances and RECs(111)(98)(146)
Proceeds from Sales of Trust Investments2,234 1,787 1,501 
Purchases of Trust Investments(2,250)(1,814)(1,473)
Proceeds from Sales of Long-Lived Assets and Lease Investments301 70 31 
Other73 76 83 
  Net Cash Provided By (Used In) Investing Activities(2,676)(3,145)(3,916)
CASH FLOWS FROM FINANCING ACTIVITIES
Net Change in Commercial Paper and Loans(352)99 474 
Proceeds from Short-Term Loan800 0 0 
Repayment of Short-Term Loans(500)0 0 
Issuance of Long-Term Debt2,450 1,900 2,750 
Redemption of Long-Term Debt(1,365)(1,250)(1,350)
Cash Dividends Paid on Common Stock(991)(950)(910)
Other(72)(56)(77)
  Net Cash Provided By (Used In) Financing Activities(30)(257)887 
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash396 (23)(116)
Cash, Cash Equivalents and Restricted Cash at Beginning of Period176 199 315 
Cash, Cash Equivalents and Restricted Cash at End of Period$572 $176 $199 
Supplemental Disclosure of Cash Flow Information:
Income Taxes Paid (Received)$297 $41 $99 
Interest Paid, Net of Amounts Capitalized$568 $539 $454 
Accrued Property, Plant and Equipment Expenditures$387 $499 $517 
See Notes to Consolidated Financial Statements.

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PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
Millions
 
                   
   
Common
Stock
 
Treasury
Stock
 
Retained
Earnings
 
Accumulated
Other
Comprehensive
Income (Loss)
 Noncontrolling Interest 
   Shs. Amount Shs. Amount  Total 
 Balance as of January 1, 2015 534
 $4,876
 (28) $(635) $8,227
 $(283) $1
 $12,186
 
 Net Income —
 —
 —
 —
 1,679
 —
 —
 1,679
 
 Other Comprehensive Income (Loss), net of tax (expense) benefit of $23 —
 —
 —
 —
 —
 (12) —
 (12) 
 Comprehensive Income               1,667
 
 Cash Dividends on Common Stock —
 —
 —
 —
 (789) —
 —
 (789) 
 Other —
 39
 —
 (36) —
 —
 —
 3
 
 Balance as of December 31, 2015 534
 $4,915
 (28) $(671) $9,117
 $(295) $1
 $13,067
 
 Net Income —
 —
 —
 —
 887
 —
 —
 887
 
 Other Comprehensive Income (Loss), net of tax (expense) benefit of $(34) —
 —
 —
 —
 —
 32
 —
 32
 
 Comprehensive Income               919
 
 Cash Dividends on Common Stock —
 —
 —
 —
 (830) —
 —
 (830) 
 Other —
 21
 (1) (46) —
 —
 (1) (26) 
 Balance as of December 31, 2016 534
 $4,936
 (29) $(717) $9,174
 $(263) $—
 $13,130
 
 Net Income —
 —
 —
 —
 1,574
 —
 —
 1,574
 
 Other Comprehensive Income (Loss), net of tax (expense) benefit of $(40) —
 —
 —
 —
 —
 34
 —
 34
 
 Comprehensive Income               1,608
 
 Cash Dividends on Common Stock —
 —
 —
 —
 (870) —
 —
 (870) 
 Other —
 25
 —
 (46) —
 —
 —
 (21) 
 Balance as of December 31, 2017 534
 $4,961
 (29) $(763) $9,878
 $(229) $—
 $13,847
 
                   
 
 Common
Stock		 Treasury
Stock		Retained
Earnings		Accumulated
Other
Comprehensive
Income (Loss)
  Shs.Amount Shs.AmountTotal
Balance as of December 31, 2017 534 $4,961 (29)$(763)$9,878 $(229)$13,847 
Net Income — — — — 1,438 — 1,438 
Cumulative Effect Adjustment to Reclassify Unrealized Net Gains on Equity Investments— — — — 176 (176)— 
Other Comprehensive Income (Loss), net of tax (expense) benefit of $(6) — — — — — 28 28 
Comprehensive Income 1,466 
Cash Dividends at $1.80 per share on Common Stock — — — — (910)0 (910)
Other — 19 (1)(45)0 0 (26)
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)0 (950)
Other 0 23 0 (23)0 0 0 
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)0 (991)
Other 0 28 0 (30)0 0 (2)
Balance as of December 31, 2020 534 $5,031  (30)$(861)$12,318 $(504)$15,984 
See Notes to Consolidated Financial Statements.





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PUBLIC SERVICE ELECTRIC AND GAS COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
Millions
 
         
   Years Ended December 31, 
   2017 2016 2015 
 OPERATING REVENUES $6,234
 $6,221
 $6,636
 
 OPERATING EXPENSES       
 Energy Costs 2,363
 2,567
 2,722
 
 Operation and Maintenance 1,434
 1,475
 1,560
 
 Depreciation and Amortization 685
 565
 892
 
 Total Operating Expenses 4,482
 4,607
 5,174
 
 OPERATING INCOME 1,752
 1,614
 1,462
 
 Other Income 92
 83
 79
 
 Other Deductions (5) (4) (4) 
 Interest Expense (303) (289) (280) 
 INCOME BEFORE INCOME TAXES 1,536
 1,404
 1,257
 
 Income Tax Expense (563) (515) (470) 
 NET INCOME $973
 $889
 $787
 
         
Years Ended December 31,
 202020192018
OPERATING REVENUES$6,608 $6,625 $6,471 
OPERATING EXPENSES
Energy Costs2,469 2,738 2,520 
Operation and Maintenance1,614 1,581 1,575 
Depreciation and Amortization887 837 770 
Gain on Asset Dispositions(1)0 0 
Total Operating Expenses4,969 5,156 4,865 
OPERATING INCOME1,639 1,469 1,606 
Net Gains (Losses) on Trust Investments3 2 (1)
Other Income (Deductions)108 83 80 
Non-Operating Pension and OPEB Credits (Costs)205 150 59 
Interest Expense(388)(361)(333)
INCOME BEFORE INCOME TAXES1,567 1,343 1,411 
Income Tax Benefit (Expense)(240)(93)(344)
NET INCOME$1,327 $1,250 $1,067 
See disclosures regarding Public Service Electric and Gas Company included in the Notes to Consolidated Financial Statements.



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


         
  Years Ended December 31, 
   2017 2016 2015 
 NET INCOME $973
 $889
 $787
 
 Other Comprehensive Income (Loss), net of tax       
 Unrealized Gains (Losses) on Available-for-Sale Securities, net of tax (expense) benefit of $0, $0 and $0 for the years ended 2017, 2016 and 2015, respectively (1) —
 (1) 
 COMPREHENSIVE INCOME $972
 $889
 $786
 
         
 Years Ended December 31,
 202020192018
NET INCOME$1,327 $1,250 $1,067 
Other Comprehensive Income (Loss), net of tax
Unrealized Gains (Losses) on Available-for-Sale Securities, net of tax (expense) benefit of $0, $(1) and $1 for the years ended 2020, 2019 and 2018, respectively1 3 (1)
COMPREHENSIVE INCOME$1,328 $1,253 $1,066 
See disclosures regarding Public Service Electric and Gas Company included in the Notes to Consolidated Financial Statements.




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PUBLIC SERVICE ELECTRIC AND GAS COMPANY
CONSOLIDATED BALANCE SHEETS
Millions
      
  December 31, 
  2017 2016 
 ASSETS 
 CURRENT ASSETS    
 Cash and Cash Equivalents$242
 $390
 
 Accounts Receivable, net of allowances of $59 in 2017 and $68 in 2016882
 810
 
 Accounts Receivable—Affiliated Companies—
 76
 
 Unbilled Revenues296
 260
 
 Materials and Supplies197
 180
 
 Prepayments44
 9
 
 Regulatory Assets211
 199
 
 Other4
 6
 
 Total Current Assets1,876
 1,930
 
 PROPERTY, PLANT AND EQUIPMENT29,117
 26,347
 
 Less: Accumulated Depreciation and Amortization(6,101) (5,760) 
 Net Property, Plant and Equipment23,016
 20,587
 
 NONCURRENT ASSETS    
 Regulatory Assets3,222
 3,319
 
 Long-Term Investments280
 299
 
 Other Special Funds46
 43
 
 Other114
 110
 
 Total Noncurrent Assets3,662
 3,771
 
 TOTAL ASSETS$28,554
 $26,288
 
      
December 31,
20202019
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents$204 $21 
Accounts Receivable, net of allowance of $196 in 2020 and $60 in 20191,004 901 
Accounts Receivable—Affiliated Companies0 1 
Unbilled Revenues, net of allowance of $10 in 2020229 239 
Materials and Supplies, net217 213 
Prepayments14 35 
Regulatory Assets369 351 
Other13 28 
Total Current Assets2,050 1,789 
PROPERTY, PLANT AND EQUIPMENT36,300 33,900 
Less: Accumulated Depreciation and Amortization(7,149)(6,623)
Net Property, Plant and Equipment29,151 27,277 
NONCURRENT ASSETS
Regulatory Assets3,872 3,677 
Operating Lease Right-of-Use Assets99 98 
Long-Term Investments222 248 
Rabbi Trust Fund51 48 
Other136 129 
Total Noncurrent Assets4,380 4,200 
 TOTAL ASSETS$35,581 $33,266 
See disclosures regarding Public Service Electric and Gas Company included in the Notes to Consolidated Financial Statements.





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PUBLIC SERVICE ELECTRIC AND GAS COMPANY
CONSOLIDATED BALANCE SHEETS
Millions
 
      
  December 31, 
  2017 2016 
 LIABILITIES AND CAPITALIZATION 
 CURRENT LIABILITIES    
 Long-Term Debt Due Within One Year$750
 $—
 
 Accounts Payable728
 718
 
 Accounts Payable—Affiliated Companies340
 260
 
 Accrued Interest78
 76
 
 Clean Energy Program128
 142
 
 Derivative Contracts—
 5
 
 Obligation to Return Cash Collateral129
 132
 
 Regulatory Liabilities47
 88
 
 Other311
 296
 
 Total Current Liabilities2,511
 1,717
 
 NONCURRENT LIABILITIES    
 Deferred Income Taxes and ITC3,391
 5,873
 
 OPEB Costs1,103
 1,009
 
 Accrued Pension Costs226
 250
 
 Regulatory Liabilities2,948
 118
 
 Environmental Costs283
 332
 
 Asset Retirement Obligations212
 213
 
 Long-Term Accrued Taxes91
 130
 
 Other114
 116
 
 Total Noncurrent Liabilities8,368
 8,041
 
 COMMITMENTS AND CONTINGENT LIABILITIES (See Note 13)
 
 
 CAPITALIZATION
   
 LONG-TERM DEBT7,841
 7,818
 
 STOCKHOLDER’S EQUITY    
 Common Stock; 150 shares authorized; issued and outstanding, 2017 and 2016—132 shares892
 892
 
 Contributed Capital1,095
 945
 
 Basis Adjustment986
 986
 
 Retained Earnings6,861
 5,888
 
 Accumulated Other Comprehensive Income—
 1
 
 Total Stockholder’s Equity9,834
 8,712
 
 Total Capitalization17,675
 16,530
 
 TOTAL LIABILITIES AND CAPITALIZATION$28,554
 $26,288
 
      
December 31,
20202019
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES
Long-Term Debt Due Within One Year$434 $259 
Commercial Paper and Loans100 362 
Accounts Payable671 639 
Accounts Payable—Affiliated Companies479 390 
Accrued Interest101 91 
Clean Energy Program143 143 
Obligation to Return Cash Collateral98 119 
Regulatory Liabilities294 234 
Other530 436 
Total Current Liabilities2,850 2,673 
NONCURRENT LIABILITIES
Deferred Income Taxes and ITC4,524 4,189 
Regulatory Liabilities2,707 3,002 
Operating Leases88 87 
Asset Retirement Obligations314 303 
OPEB Costs485 495 
Accrued Pension Costs612 501 
Environmental Costs236 294 
Long-Term Accrued Taxes7 115 
Other154 136 
Total Noncurrent Liabilities9,127 9,122 
COMMITMENTS AND CONTINGENT LIABILITIES (See Note 15)00
CAPITALIZATION
LONG-TERM DEBT10,475 9,568 
STOCKHOLDER’S EQUITY
Common Stock; 150 shares authorized; issued and outstanding, 2020 and 2019—132 shares892 892 
Contributed Capital1,170 1,095 
Basis Adjustment986 986 
Retained Earnings10,078 8,928 
Accumulated Other Comprehensive Income (Loss)3 2 
Total Stockholder’s Equity13,129 11,903 
   Total Capitalization23,604 21,471 
TOTAL LIABILITIES AND CAPITALIZATION$35,581 $33,266 
See disclosures regarding Public Service Electric and Gas Company included in the Notes to Consolidated Financial Statements.

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PUBLIC SERVICE ELECTRIC AND GAS COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
Millions
         
   Years Ended December 31, 
   2017 2016 2015 
 CASH FLOWS FROM OPERATING ACTIVITIES       
 Net Income $973
 $889
 $787
 
 Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:       
 Depreciation and Amortization 685
 565
 892
 
 Provision for Deferred Income Taxes and ITC 616
 658
 386
 
 Non-Cash Employee Benefit Plan Costs 50
 72
 95
 
 Cost of Removal (107) (131) (120) 
 Net Change in Other Regulatory Assets and Liabilities (188) (138) (48) 
 Net Change in Certain Current Assets and Liabilities       
      Accounts Receivable and Unbilled Revenues (106) (84) 165
 
      Materials and Supplies (13) (7) (15) 
      Prepayments (35) 22
 11
 
 Accounts Payable 1
 (29) 45
 
      Accounts Receivable/Payable—Affiliated Companies, net 101
 199
 —
 
      Other Current Assets and Liabilities 17
 8
 (29) 
 Employee Benefit Plan Funding and Related Payments (68) (82) (91) 
 Other (87) (48) 47
 
 Net Cash Provided By (Used In) Operating Activities 1,839
 1,894
 2,125
 
 CASH FLOWS FROM INVESTING ACTIVITIES       
 Additions to Property, Plant and Equipment (2,919) (2,816) (2,692) 
 Proceeds from Sales of Available-for-Sale Securities 36
 22
 21
 
 Investments in Available-for-Sale Securities (37) (24) (22) 
 Solar Loan Investments 7
 14
 11
 
 Other 10
 15
 11
 
 Net Cash Provided By (Used In) Investing Activities (2,903) (2,789) (2,671) 
 CASH FLOWS FROM FINANCING ACTIVITIES       
 Net Change in Short-Term Debt —
 (153) 153
 
 Issuance of Long-Term Debt 775
 1,275
 850
 
 Redemption of Long-Term Debt —
 (271) (300) 
 Redemption of Securitization Debt —
 —
 (259) 
 Contributed Capital 150
 250
 —
 
 Other (9) (14) (10) 
 Net Cash Provided By (Used In) Financing Activities 916
 1,087
 434
 
 Net Increase (Decrease) in Cash and Cash Equivalents (148) 192
 (112) 
 Cash and Cash Equivalents at Beginning of Period 390
 198
 310
 
 Cash and Cash Equivalents at End of Period $242
 $390
 $198
 
 Supplemental Disclosure of Cash Flow Information:       
 Income Taxes Paid (Received) $(104) $(295) $(28) 
 Interest Paid, Net of Amounts Capitalized $294
 $273
 $261
 
 Accrued Property, Plant and Equipment Expenditures $429
 $420
 $396
 
         
Years Ended December 31,
 202020192018
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income$1,327 $1,250 $1,067 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization887 837 770 
Provision for Deferred Income Taxes and ITC53 (28)405 
Non-Cash Employee Benefit Plan (Credits) Costs(103)(62)37 
Cost of Removal(106)(108)(160)
Net Change in Other Regulatory Assets and Liabilities(101)25 (153)
Net Change in Certain Current Assets and Liabilities
     Accounts Receivable and Unbilled Revenues(100)(18)65 
     Materials and Supplies(2)(14)1 
     Prepayments21 (9)14 
Accounts Payable44 (59)64 
     Accounts Receivable/Payable—Affiliated Companies, net80 203 (139)
     Other Current Assets and Liabilities60 62 5 
Employee Benefit Plan Funding and Related Payments(4)(21)(85)
Other(103)(23)(38)
Net Cash Provided By (Used In) Operating Activities1,953 2,035 1,853 
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment(2,507)(2,542)(2,896)
Proceeds from Sales of Trust Investments40 36 20 
Purchases of Trust Investments(40)(34)(22)
Solar Loan Investments13 8 (5)
Other12 10 9 
Net Cash Provided By (Used In) Investing Activities(2,482)(2,522)(2,894)
CASH FLOWS FROM FINANCING ACTIVITIES
Net Change in Commercial Paper and Loans(262)90 272 
Issuance of Long-Term Debt1,350 1,150 1,350 
Redemption of Long-Term Debt(259)(500)(750)
Contributed Capital75 0 0 
Cash Dividend Paid(175)(250)0 
Other(17)(14)(14)
Net Cash Provided By (Used In) Financing Activities712 476 858 
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash183 (11)(183)
Cash, Cash Equivalents and Restricted Cash at Beginning of Period50 61 244 
Cash, Cash Equivalents and Restricted Cash at End of Period$233 $50 $61 
Supplemental Disclosure of Cash Flow Information:
Income Taxes Paid (Received)$157 $(48)$94 
Interest Paid, Net of Amounts Capitalized$369 $343 $318 
Accrued Property, Plant and Equipment Expenditures$323 $335 $350 
See disclosures regarding Public Service Electric and Gas Company included in the Notes to Consolidated Financial Statements.





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PUBLIC SERVICE ELECTRIC AND GAS COMPANY
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER’S EQUITY
Millions
               
   Common Stock 
Contributed
Capital
 
Basis
Adjustment
 
Retained
Earnings
 
Accumulated
Other
Comprehensive
Income (Loss)
 Total 
 Balance as of January 1, 2015 $892
 $695
 $986
 $4,212
 $2
 $6,787
 
 Net Income —
 —
 —
 787
 —
 787
 
 Other Comprehensive Income, net of tax (expense) benefit of $0 —
 —
 —
 —
 (1) (1) 
 Comprehensive Income          
786
 
 Balance as of December 31, 2015 $892
 $695
 $986
 $4,999
 $1
 $7,573
 
 Net Income —
 —
 —
 889
 —
 889
 
 Other Comprehensive Income, net of tax (expense) benefit of $0 —
 —
 —
 —
 —
 —
 
 Comprehensive Income          
889
 
 Contributed Capital 
 250
 —
 —
 —
 250
 
 Balance as of December 31, 2016 $892
 $945
 $986
 $5,888
 $1
 $8,712
 
 Net Income —
 —
 —
 973
 —
 973
 
 Other Comprehensive Income, net of tax (expense) benefit of $0 —
 —
 —
 —
 (1) (1) 
 Comprehensive Income          
972
 
 Contributed Capital —
 150
 —
 —
 —
 150
 
 Balance as of December 31, 2017 $892
 $1,095
 $986
 $6,861
 $—
 $9,834
 
               
Common StockContributed
Capital		Basis
Adjustment		Retained
Earnings		Accumulated
Other
Comprehensive
Income (Loss)		Total
Balance as of December 31, 2017$892 $1,095 $986 $6,861 $0 $9,834 
Net Income— — — 1,067 — 1,067 
Other Comprehensive Income (Loss), net of tax (expense) benefit of $1— — — — (1)(1)
Comprehensive Income1,066 
Balance as of December 31, 2018$892 $1,095 $986 $7,928 $(1)$10,900 
Net Income— — — 1,250 — 1,250 
Other Comprehensive Income (Loss), net of tax (expense) benefit of $(1)— — — — 3 3 
Comprehensive Income1,253 
Cash Dividends Paid— — — (250)— (250)
Balance as of December 31, 2019$892 $1,095 $986 $8,928 $2 $11,903 
Net Income— — — 1,327 — 1,327 
Other Comprehensive Income (Loss), net of tax (expense) benefit of $0— — — — 1 1 
Comprehensive 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 $3 $13,129 
See disclosures regarding Public Service Electric and Gas Company included in the Notes to Consolidated Financial Statements.



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PSEG POWER LLC
CONSOLIDATED STATEMENTS OF OPERATIONS
Millions
 
         
   Years Ended December 31, 
   2017 2016 2015 
 OPERATING REVENUES $3,930
 $4,023
 $4,928
 
 OPERATING EXPENSES       
 Energy Costs 1,983
 1,986
 2,150
 
 Operation and Maintenance 1,038
 1,143
 1,057
 
 Depreciation and Amortization 1,268
 881
 291
 
 Total Operating Expenses 4,289
 4,010
 3,498
 
 OPERATING INCOME (LOSS) (359) 13
 1,430
 
 Income from Equity Method Investments 14
 11
 14
 
 Other Income 213
 102
 169
 
 Other Deductions (56) (57) (72) 
 Other-Than-Temporary Impairments (12) (28) (53) 
 Interest Expense (50) (84) (121) 
 INCOME (LOSS) BEFORE INCOME TAXES (250) (43) 1,367
 
 Income Tax Benefit (Expense) 729
 61
 (511) 
 NET INCOME $479
 $18
 $856
 
         
Years Ended December 31,
 202020192018
OPERATING REVENUES$3,634 $4,385 $4,146 
OPERATING EXPENSES
Energy Costs1,821 2,118 2,197 
Operation and Maintenance964 1,040 1,053 
Depreciation and Amortization368 377 354 
(Gain) Loss on Asset Dispositions(122)402 (54)
Total Operating Expenses3,031 3,937 3,550 
OPERATING INCOME603 448 596 
Income from Equity Method Investments14 14 15 
Net Gains (Losses) on Trust Investments241 253 (140)
Other Income (Deductions)12 54 21 
Non-Operating Pension and OPEB (Costs) Credits33 21 15 
Interest Expense(121)(119)(76)
INCOME BEFORE INCOME TAXES782 671 431 
Income Tax Benefit (Expense)(188)(203)(66)
NET INCOME$594 $468 $365 
See disclosures regarding PSEG Power LLC included in the Notes to Consolidated Financial Statements.





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PSEG POWER LLC
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Millions

         
  Years Ended December 31, 
   2017 2016 2015 
 NET INCOME $479
 $18
 $856
 
 Other Comprehensive Income (Loss), net of tax       
 Unrealized Gains (Losses) on Available-for-Sale Securities, net of tax (expense) benefit of $(39), $(41) and $32 for the years ended 2017, 2016 and 2015, respectively 46
 42
 (25) 
 Unrealized Gains (Losses) on Cash Flow Hedges, net of tax (expense) benefit of $0, $0 and $7 for the years ended 2017, 2016 and 2015, respectively —
 —
 (11) 
 Pension/OPEB adjustment, net of tax (expense) benefit of $(3), $9 and $(16) for the years ended 2017, 2016 and 2015, respectively (7) (13) 24
 
 Other Comprehensive Income (Loss), net of tax 39
 29
 (12) 
 COMPREHENSIVE INCOME $518
 $47
 $844
 
         
 Years Ended December 31,
 202020192018
NET INCOME$594 $468 $365 
Other Comprehensive Income (Loss), net of tax
Unrealized Gains (Losses) on Available-for-Sale Securities, net of tax (expense) benefit of $(15), $(22) and $9 for the years ended 2020, 2019 and 2018, respectively21 32 (13)
Pension/OPEB adjustment, net of tax (expense) benefit of $16, $13 and $(16) for the years ended 2020, 2019 and 2018, respectively(39)(45)41 
Other Comprehensive Income (Loss), net of tax(18)(13)28 
COMPREHENSIVE INCOME$576 $455 $393 
See disclosures regarding PSEG Power LLC included in the Notes to Consolidated Financial Statements.



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CONSOLIDATED BALANCE SHEETS
Millions

      
  December 31, 
  2017 2016 
 ASSETS 
 CURRENT ASSETS    
 Cash and Cash Equivalents$32
 $11
 
 Accounts Receivable380
 276
 
 Accounts Receivable—Affiliated Companies221
 205
 
 Short-Term Loan to Affiliate—
 87
 
 Fuel289
 326
 
 Materials and Supplies, net376
 381
 
 Derivative Contracts29
 162
 
 Prepayments11
 10
 
 Other3
 2
 
 Total Current Assets1,341
 1,460
 
 PROPERTY, PLANT AND EQUIPMENT11,755
 12,655
 
 Less: Accumulated Depreciation and Amortization(3,159) (4,135) 
 Net Property, Plant and Equipment8,596
 8,520
 
 NONCURRENT ASSETS    
 NDT Fund2,133
 1,859
 
 Long-Term Investments87
 102
 
 Goodwill16
 16
 
 Other Intangibles114
 98
 
 Other Special Funds57
 53
 
 Derivative Contracts7
 24
 
 Other67
 61
 
 Total Noncurrent Assets2,481
 2,213
 
 TOTAL ASSETS$12,418
 $12,193
 
      
December 31,
20202019
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents$27 $21 
Accounts Receivable328 309 
Accounts Receivable—Affiliated Companies317 408 
Short-Term Loan to Affiliate161 149 
Fuel277 310 
Materials and Supplies, net382 372 
Derivative Contracts60 113 
Prepayments16 11 
Assets Held for Sale0 28 
Other2 5 
Total Current Assets1,570 1,726 
PROPERTY, PLANT AND EQUIPMENT11,872 11,699 
Less: Accumulated Depreciation and Amortization(3,624)(3,273)
Net Property, Plant and Equipment8,248 8,426 
NONCURRENT ASSETS
Operating Lease Right-of-Use Assets61 71 
NDT Fund2,501 2,216 
Long-Term Investments64 66 
Other Intangibles158 149 
Rabbi Trust Fund66 62 
Derivative Contracts9 24 
Other27 65 
Total Noncurrent Assets2,886 2,653 
TOTAL ASSETS$12,704 $12,805 
See disclosures regarding PSEG Power LLC included in the Notes to Consolidated Financial Statements.



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CONSOLIDATED BALANCE SHEETS
Millions
 
      
  December 31, 
  2017 2016 
 LIABILITIES AND MEMBER’S EQUITY 
 CURRENT LIABILITIES    
 Long-Term Debt Due Within One Year$250
 $—
 
 Accounts Payable712
 539
 
 Accounts Payable—Affiliated Companies57
 25
 
 Short-Term Loan from Affiliate281
 —
 
 Derivative Contracts16
 8
 
 Accrued Interest20
 20
 
 Other99
 88
 
 Total Current Liabilities1,435
 680
 
 NONCURRENT LIABILITIES    
 Deferred Income Taxes and ITC1,406
 2,170
 
 Asset Retirement Obligations810
 511
 
 OPEB Costs283
 251
 
 Derivative Contracts5
 3
 
 Accrued Pension Costs184
 191
 
 Long-Term Accrued Taxes52
 77
 
 Other140
 129
 
 Total Noncurrent Liabilities2,880
 3,332
 
 COMMITMENTS AND CONTINGENT LIABILITIES (See Note 13)
 
 
 
LONG-TERM DEBT

2,136
 2,382
 
 MEMBER’S EQUITY    
 Contributed Capital2,214
 2,214
 
 Basis Adjustment(986) (986) 
 Retained Earnings4,911
 4,782
 
 Accumulated Other Comprehensive Loss(172) (211) 
 Total Member’s Equity5,967
 5,799
 
 TOTAL LIABILITIES AND MEMBER’S EQUITY$12,418
 $12,193
 
      
December 31,
20202019
LIABILITIES AND MEMBER’S EQUITY
CURRENT LIABILITIES
Long-Term Debt Due Within One Year$950 $406 
Accounts Payable459 505 
Accounts Payable—Affiliated Companies13 5 
Derivative Contracts21 31 
Accrued Interest16 21 
Other101 91 
Total Current Liabilities1,560 1,059 
NONCURRENT LIABILITIES
Deferred Income Taxes and ITC1,936 1,876 
Operating Leases51 62 
Asset Retirement Obligations895 781 
OPEB Costs197 192 
Accrued Pension Costs321 284 
Derivative Contracts4 1 
Long-Term Accrued Taxes57 115 
Other79 111 
Total Noncurrent Liabilities3,540 3,422 
COMMITMENTS AND CONTINGENT LIABILITIES (See Note 15)00
LONG-TERM DEBT
1,392 2,434 
MEMBER’S EQUITY
Contributed Capital2,310 2,214 
Basis Adjustment(986)(986)
Retained Earnings5,307 5,063 
Accumulated Other Comprehensive Loss(419)(401)
Total Member’s Equity6,212 5,890 
TOTAL LIABILITIES AND MEMBER’S EQUITY$12,704 $12,805 
See disclosures regarding PSEG Power LLC included in the Notes to Consolidated Financial Statements.





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CONSOLIDATED STATEMENTS OF CASH FLOWS
Millions
         
   Years Ended December 31, 
   2017 2016 2015 
 CASH FLOWS FROM OPERATING ACTIVITIES       
 Net Income $479
 $18
 $856
 
 Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:       
 Depreciation and Amortization 1,268
 881
 291
 
 Amortization of Nuclear Fuel 199
 203
 213
 
 Provision for Deferred Income Taxes and ITC (807) (208) 261
 
 Interest Accretion on Asset Retirement Obligation 30
 26
 26
 
 Net Realized and Unrealized (Gains) Losses on Energy Contracts and Other Derivatives 188
 183
 (143) 
 Emission Allowances and Renewable Energy Credit (REC) Compliance Accrual 103
 109
 104
 
 Impairment Costs for Early Plant Retirements —
 102
 —
 
 Non-Cash Employee Benefit Plan Costs 28
 39
 48
 
 Net Realized (Gains) Losses and (Income) Expense from NDT Fund (156) (26) (38) 
 Net Change in Certain Current Assets and Liabilities       
      Fuel, Materials and Supplies 42
 31
 62
 
      Margin Deposit (90) (76) 122
 
      Accounts Receivable (45) (71) 63
 
      Accounts Payable 39
 (22) (46) 
      Accounts Receivable/Payable—Affiliated Companies, net (2) 6
 (84) 
      Other Current Assets and Liabilities 10
 10
 (36) 
 Employee Benefit Plan Funding and Related Payments (7) (13) (11) 
 Other 47
 63
 18
 
 Net Cash Provided By (Used In) Operating Activities 1,326
 1,255
 1,706
 
 CASH FLOWS FROM INVESTING ACTIVITIES       
 Additions to Property, Plant and Equipment (1,231) (1,343) (1,117) 
 Purchase of Emissions Allowances and RECs (117) (99) (106) 
 Proceeds from Sales of Available-for-Sale Securities 2,182
 739
 1,422
 
 Investments in Available-for-Sale Securities (2,199) (766) (1,455) 
 Short-Term Loan—Affiliated Company 87
 276
 221
 
 Other 46
 46
 34
 
 Net Cash Provided By (Used In) Investing Activities (1,232) (1,147) (1,001) 
 CASH FLOWS FROM FINANCING ACTIVITIES       
 Issuance of Long-Term Debt —
 700
 —
 
 Cash Dividend Paid (350) (250) (400) 
 Redemption of Long-Term Debt —
 (553) (300) 
 Short-Term Loan—Affiliated Company 281
 —
 —
 
 Other (4) (6) (2) 
 Net Cash Provided By (Used In) Financing Activities (73) (109) (702) 
 Net Increase (Decrease) in Cash and Cash Equivalents 21
 (1) 3
 
 Cash and Cash Equivalents at Beginning of Period 11
 12
 9
 
 Cash and Cash Equivalents at End of Period $32
 $11
 $12
 
 Supplemental Disclosure of Cash Flow Information:       
 Income Taxes Paid (Received) $77
 $50
 $393
 
 Interest Paid, Net of Amounts Capitalized $48
 $81
 $116
 
 Accrued Property, Plant and Equipment Expenditures $293
 $244
 $114
 
         
Years Ended December 31,
202020192018
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income$594 $468 $365 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization368 377 354 
Amortization of Nuclear Fuel184 178 187 
(Gain) Loss on Asset Dispositions(122)402 (54)
Emission Allowances and Renewable Energy Credit (REC) Compliance Accrual151 108 97 
Provision for Deferred Income Taxes and ITC60 248 206 
Non-Cash Employee Benefit Plan Costs(5)7 23 
Interest Accretion on Asset Retirement Obligation42 40 41 
Net Realized and Unrealized (Gains) Losses on Energy Contracts and Other Derivatives80 (290)116 
Net (Gains) Losses and (Income) Expense from NDT Fund(278)(296)98 
Net Change in Certain Current Assets and Liabilities
     Fuel, Materials and Supplies18 (1)(39)
     Cash Collateral(10)349 (247)
     Accounts Receivable19 (32)51 
     Accounts Payable(23)5 (13)
     Accounts Receivable/Payable—Affiliated Companies, net90 (112)(56)
     Other Current Assets and Liabilities(3)14 (40)
Employee Benefit Plan Funding and Related Payments(8)(11)(9)
Other(46)25 4 
Net Cash Provided By (Used In) Operating Activities1,111 1,479 1,084 
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment(404)(607)(996)
Purchase of Emissions Allowances and RECs(111)(98)(146)
Proceeds from Sales of Trust Investments2,083 1,658 1,423 
Purchases of Trust Investments(2,097)(1,685)(1,392)
Proceeds from Sales of Long-Lived Assets151 70 21 
Short-Term Loan to Affiliate(12)(149)0 
Other42 50 39 
Net Cash Provided By (Used In) Investing Activities(348)(761)(1,051)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of Long-Term Debt0 0 700 
Cash Dividend Paid(350)(525)(400)
Redemption of Long-Term Debt(406)0 (250)
Short-Term Loan from Affiliate0 (193)(88)
Other(1)(1)(5)
Net Cash Provided By (Used In) Financing Activities(757)(719)(43)
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash6 (1)(10)
Cash, Cash Equivalents and Restricted Cash at Beginning of Period21 22 32 
Cash, Cash Equivalents and Restricted Cash at End of Period$27 $21 $22 
Supplemental Disclosure of Cash Flow Information:
Income Taxes Paid (Received)$127 $(41)$(92)
Interest Paid, Net of Amounts Capitalized$119 $113 $73 
Accrued Property, Plant and Equipment Expenditures$64 $164 $167 
See disclosures regarding PSEG Power LLC included in the Notes to Consolidated Financial Statements.





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CONSOLIDATED STATEMENTS OF MEMBER’S EQUITY
Millions
 
             
   
Contributed
Capital
 
Basis
Adjustment
 
Retained
Earnings
 
Accumulated
Other
Comprehensive
Income (Loss)
 Total 
 Balance as of January 1, 2015 $2,214
 $(986) $4,558
 $(228) $5,558
 
 Net Income —
 —
 856
 —
 856
 
 Other Comprehensive Income (Loss), net of tax (expense) benefit of $23 —
 —
 —
 (12) (12) 
 Comprehensive Income         844
 
 Cash Dividends Paid —
 —
 (400) —
 (400) 
 Balance as of December 31, 2015 $2,214
 $(986) $5,014
 $(240) $6,002
 
 Net Income —
 —
 18
 —
 18
 
 Other Comprehensive Income (Loss), net of tax (expense) benefit of $(32) —
 —
 —
 29
 29
 
 Comprehensive Income         47
 
 Cash Dividends Paid —
 —
 (250) —
 (250) 
 Balance as of December 31, 2016 $2,214
 $(986) $4,782
 $(211) $5,799
 
 Net Income —
 —
 479
 —
 479
 
 Other Comprehensive Income (Loss), net of tax (expense) benefit of $(42) —
 —
 —
 39
 39
 
 Comprehensive Income         518
 
 Cash Dividends Paid —
 —
 (350) —
 (350) 
 Balance as of December 31, 2017 $2,214
 $(986) $4,911
 $(172) $5,967
 
             
Contributed
Capital		Basis
Adjustment		Retained
Earnings		Accumulated
Other
Comprehensive
Income (Loss)		Total
Balance as of December 31, 2017$2,214 $(986)$4,911 $(172)$5,967 
Net Income— — 365 — 365 
Cumulative Effect Adjustment to Reclassify Unrealized Net Gains on Equity Investments— — 175 (175)— 
Other Comprehensive Income (Loss), net of tax (expense) benefit of $(7)— — — 28 28 
Comprehensive Income393 
Cash Dividends Paid— — (400)— (400)
Balance as of December 31, 2018$2,214 $(986)$5,051 $(319)$5,960 
Net Income— — 468 — 468 
Cumulative Effect Adjustment to Reclassify Stranded Tax Effects Resulting from the Change in the Federal Corporate Income Tax Rate— — 69 (69)— 
Other Comprehensive Income (Loss), net of tax (expense) benefit of $(9)— — — (13)(13)
Comprehensive Income455 
Cash Dividends Paid— — (525)— (525)
Balance as of December 31, 2019$2,214 $(986)$5,063 $(401)$5,890 
Net Income— — 594 — 594 
Other Comprehensive Income (Loss), net of tax (expense) benefit of $1— — — (18)(18)
Comprehensive Income576 
Cash Dividends Paid— — (350)— (350)
Non-Cash Contributed Capital Related to Debt Exchange96 — — — 96 
Balance as of December 31, 2020$2,310 $(986)$5,307 $(419)$6,212 
See disclosures regarding PSEG Power LLC included in the Notes to Consolidated Financial Statements.





























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Note 1. Organization, Basis of Presentation and Summary of Significant Accounting Policies
Public Service Enterprise Group Incorporated (PSEG) is a holding company with a diversified business mix within the energy industry. Its operations are primarily in the Northeastern and Mid-Atlantic United States and in other select markets. PSEG’s 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 (Power)(PSEG Power)—which is a multi-regional energy supply company that integrates the operations of its merchant nuclear and fossil generating assets with its power marketing businesses and fuel supply functions through competitive energy sales in well-developed energy markets primarily in the Northeast and Mid-Atlantic United States through its principal direct wholly owned subsidiaries. In addition, PSEG Power owns and operates solar generation in various states. PSEG Power’s subsidiaries are subject to regulation by FERC, the Nuclear Regulatory Commission (NRC), the Environmental Protection Agency (EPA) and the states in which they operate.
PSEG’s other direct wholly owned subsidiaries are: PSEG Long Island LLC (PSEG LI), which operates the Long Island Power Authority’s (LIPA) electric transmission and distribution (T&D) system under an Amended and Restated Operations Services Agreement (OSA); PSEG Energy Holdings L.L.C. (Energy Holdings), which primarily hasearns it revenues from its portfolio of lease investments and holds our investment in leveraged leases;offshore wind ventures; and PSEG Services Corporation (Services), which provides certain management, administrative and general services to PSEG and its subsidiaries at cost.
Basis of Presentation
The respective financial statements included herein have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (SEC) applicable to Annual Reports on Form 10-K and in accordance with accounting guidance generally accepted in the United States (GAAP).
Significant Accounting Policies
Principles of Consolidation
Each company consolidates those entities in which it has a controlling interest or is the primary beneficiary. See Note 4.5. Variable Interest Entity. Entities over which the companies exhibit significant influence, but do not have a controlling interest and/or are not the primary beneficiary, are accounted for under the equity method of accounting. 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 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 and/or competitive position, the associated Regulatory Asset or Liability is charged or credited to income. Management believes that PSE&G’s transmission and distributionT&D businesses continue to meet the accounting requirements for rate-regulated entities. For additional information, see Note 6.7. Regulatory Assets and Liabilities.
Cash, Cash Equivalents and Restricted Cash
The followingprovides 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
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December 31, 2019 and 2020. Restricted cash consists primarily of deposits received related to various construction projects at PSE&G.
PSE&GPSEG PowerOther (A)Consolidated
 Millions
As of December 31, 2019
Cash and Cash Equivalents$21 $21 $105 $147 
Restricted Cash in Other Current Assets11 0 0 11 
Restricted Cash in Other Noncurrent Assets18 0 0 18 
Cash, Cash Equivalents and Restricted Cash$50 $21 $105 $176 
As of December 31, 2020
Cash and Cash Equivalents$204 $27 $312 $543 
Restricted Cash in Other Current Assets7 0 0 7 
Restricted Cash in Other Noncurrent Assets22 0 0 22 
Cash, Cash Equivalents and Restricted Cash$233 $27 $312 $572 
(A)Includes amounts applicable to PSEG (parent company), 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.

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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 Power and PSEG.
For cash flow hedges, the portion of the derivative gain or loss that is effective in offsetting the change in the hedgedon a derivative instrument designated and qualifying as a cash flows of the underlying exposureflow hedge is deferred in Accumulated Other Comprehensive Income (Loss) until earnings are affected by the variability of cash flows of the hedged transaction. Any hedge ineffectiveness is included in current period earnings.
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 16.18. 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
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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 16.18. 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 Power generally reports electricity sales and purchases conducted with those individual ISOs 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 isare 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 Operations and Maintenance (O&M) Expense, respectively. See Note 4.5. Variable Interest Entity for further information.

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The majority of Energy Holdings' revenues relate to its investments in leveraged leases. Income on leveraged leases is recognized by a method which produces a constant rate of return on the outstanding net investment in the lease, net of the related deferred tax liability, in the years in which the net investment is positive. Any gains or losses incurred as a result of a lease termination are recorded as revenues as these events occur in the ordinary course of business of managing the investment portfolio.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 depreciable 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:
202020192018
 Avg RateAvg RateAvg Rate
Electric Transmission2.41 %2.41 %2.42 %
Electric Distribution2.55 %2.54 %2.51 %
Gas Distribution1.84 %1.85 %1.61 %
         
   2017 2016 2015 
   Avg Rate Avg Rate Avg Rate 
 Electric Transmission 2.41% 2.39% 2.42% 
 Electric Distribution 2.51% 2.49% 2.50% 
 Gas Distribution 1.63% 1.63% 1.64% 
         
PSEG Power calculates depreciation on generation-related assets under the straight-line method based on the assets’ estimated useful lives. The estimated useful lives are:
•general plant assets—3 years to 20 years
•fossil production assets—30 years to 7056 years
•nuclear generation assets—approximately 60 years to 80 years
pumped storage facilities—76 years
•solar assets—25 years to 35 years
Allowance for Funds Used During Construction (AFUDC) and Interest Capitalized During Construction (IDC)
AFUDC represents the cost of debt and equity funds used to finance the construction of new utility assets at PSE&G. IDC represents the cost of debt used to finance construction at PSEG Power. 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, 2017, 20162020, 2019 and 20152018 were as follows:
 AFUDC/IDC Capitalized
 202020192018
 MillionsAvg RateMillionsAvg RateMillionsAvg Rate
PSE&G$112 7.86 %$81 7.22 %$70 7.74 %
PSEG Power$10 4.60 %$27 4.60 %$67 4.60 %
94
               
   AFUDC/IDC Capitalized 
   2017 2016 2015 
   Millions Avg Rate Millions Avg Rate Millions Avg Rate 
 PSE&G $73
 7.42% $66
 7.81% $65
 8.01% 
 Power $78
 4.60% $54
 4.87% $27
 5.14% 
               

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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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 sharingtax-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 20.22. Income Taxes for further discussion.



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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. See Note 3. Early Plant Retirements for more information.
For PSEG Power, cash flows for long-lived assets and asset groups are determined at the lowest level for which identifiable cash flows are largely independent of the cash flows of other assets and liabilities. The cash flows from the generation units are generally evaluated at a regional portfolio level (PJM, NYISO, ISO-NE) along with cash flows generated from the customer supply and risk management activities, inclusive of cash flows from contracts, including those that are accounted for as derivatives and meet the NPNS scope exception. 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 (typically PSEG Power’s solar plantsunits and Kalaeloa). See Note 4. Early Plant Retirements/Asset Dispositions for more information on impairment assessments performed on PSEG Power’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 plantasset subject to lease using specific assumptions tailored to each plant.asset. Those valuations are compared to the recorded residual values to determine if an impairment is warranted.
Cash and Cash Equivalents
Cash equivalents consist of short-term, highly liquid investments with original maturities of three months or less.
Accounts Receivable—Allowance for Doubtful AccountsCredit 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 doubtful accounts.an allowance for credit losses. The allowance for doubtful accountscredit losses reflects PSE&G’s best estimatesestimate of losses on the accounts receivableaccount balances. The allowance is based on PSE&G’s projection of accounts receivable aging, historical experience, write-off forecastseconomic factors and other currently available evidence.evidence, including the estimated impact of the ongoing coronavirus pandemic on the outstanding balances as of December 31, 2020. PSE&G’s electric bad debt expense is recovered through the Societal Benefits Clause 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
PSE&G’s and PSEG Power’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 Power is valued at the lower of average cost or market and includes stored natural gas, coal, fuel oil and propane used to generate power and to satisfy obligations under PSEG Power’s gas supply contracts with PSE&G. The costs of fuel, including initial transportation costs, are included in inventory when purchased and charged to Energy Costs when used or sold. The cost
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of nuclear fuel is capitalized within Property, Plant and Equipment and amortized to fuel expense using the units-of-production method.
In 2020, PSEG Power recorded a $2 million lower of cost or market (LOCOM) adjustment to its fuel oil inventory due to the decline in market pricing.
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 Power capitalizes costs, including those related to its jointly-owned facilities whichthat increase the capacity, improve or extend the life of an existing asset,asset; represent a newly acquired or constructed assetasset; 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 Power also capitalizes spare parts that meet specific criteria. Capitalized spares are depreciated over the remaining lives of their associated assets.

Leases
Effective January 1, 2019, PSEG and its subsidiaries adopted new accounting guidance which requires lessees to recognize leases with a term greater than 12 months on the balance sheet using a right-of-use asset approach.
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, PSE&G and PSEG Power. 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 and PSEG Power’s incremental borrowing rates are generally unsecured rates. Having calculated simulated secured rates for each of PSEG and PSEG Power, it was determined that the difference between the unsecured borrowing rates and the simulated secured rates had an immaterial effect on their recorded Operating Lease Right-of-Use Assets and Operating Lease Liabilities. Services, PSEG LI and other subsidiaries of PSEG that do not borrow funds or issue debt may enter into leases. Since these companies do not have credit ratings and related incremental borrowing rates, PSEG has determined that it is appropriate for these companies to use the incremental borrowing rate of PSEG, the parent company.
Lease terms may include options to extend or terminate the lease when it is reasonably certain that such options will be exercised.
PSEG and its subsidiaries have lease agreements with lease and non-lease components. For real estate, equipment and vehicle leases, the lease and non-lease components are accounted for as a single lease component.
Lessor—Property subject to operating leases, where PSEG or one of its subsidiaries is the lessor, is included in Property, Plant and Equipment and rental income from these leases is included in Operating Revenues.
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PSEG and its subsidiaries, have lease agreements with lease and non-lease components, which are primarily related to domestic energy generation including solar generation facilities. 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.
Available-for-Sale SecuritiesEnergy 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 Power’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.
RealizedUnrealized gains and losses on available-for-sale securitiesequity security investments are recorded in earnings andNet Income. The debt securities are classified as available-for-sale with the unrealized gains and losses on such securities are recorded as a component of Accumulated Other Comprehensive Income (Loss). Securities with unrealizedRealized gains and losses that are deemed to be other-than-temporarily impairedon both equity and available-for-sale debt security investments are recorded in earnings.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 9. Available-for-Sale Securities11. 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) for all plan assets.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 because it is restricted.asset.
Pursuant to the OSA, Servco records expense only to the extent of itsfor contributions to its pension plan trusts and for OPEB payments made to retirees.
See Note 12.14. Pension, and Other Postretirement Benefits (OPEB) and Savings Plans for further discussion.
Basis Adjustment
PSE&G and PSEG Power have recorded a Basis Adjustment in their respective Consolidated Balance Sheets 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$986 million,, net of tax, was recorded as a Basis Adjustment on PSE&G’s and PSEG Power’s Consolidated Balance Sheets. The $986$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.
Note 2. Recent Accounting Standards
New Standards Issued and Adopted in 2020
Business Combinations: Clarifying the Definition of a Business
This accounting standard was issued mainly to provide more consistency in how the definition of a business is applied to acquisitions or dispositions. The new guidance will generally reduce the number of transactions that will require treatment as a business combination. The definition of a business now includes consideration of whether substantially all the fair value of the gross assets acquired or disposed of is concentrated in a single identifiable asset or a group of similar identifiable assets. If this condition is met, the transaction would not qualify as a business.
The standard is effective for annual and interim periods beginning after December 15, 2017; however, entities were able to adopt it for transactions that closed before the effective date but had not been reported in financial statements that had been issued or made available for issuance. PSEG adopted this standard in the third quarter 2017 with the acquisition of a solar project. This standard upon adoption had no impact on PSEG’s financial statements.
Revenue from Contracts with Customers
This accounting standard clarifies the principles for recognizing revenue and removes inconsistencies in revenue recognition requirements; improves comparability of revenue recognition practices across entities, industries, jurisdictions and capital markets; and provides improved disclosures.

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The guidance provides a five-step model to be used for recognizing revenue for the transfer of promised goods and services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods and services.
The standard is effective for annual and interim reporting periods beginning after December 15, 2017. PSEG adopted this standard on January 1, 2018. PSEG will elect the full retrospective method of transition. Under this method, PSEG will restate its prior period financial statements to align with the 2018 presentation.
PSEG has evaluated existing contracts and revenue streams for potential changes under the new revenue recognition standard. Included in the scope of the new standard are PSE&G’s regulated revenue recorded under tariffs, including the sale of default supply of electric and gas commodity, and the distribution of electricity and gas to retail residential and commercial and industrial customers, and transmission revenues. Tariff revenues comprise substantially all of PSE&G’s revenue. PSEG expects no material change in revenue recognition of PSE&G’s regulated revenue recorded under tariffs. PSE&G’s revenue from contracts with customers will continue to be recorded as electricity or gas is delivered to the customer. Certain reclassifications of PSE&G’s revenue streams will affect Operating Revenues and Operating Expenses due to the application of this standard.
Also included in the scope of the new standard are Power’s electricity, gas and related product sales. Certain reclassifications of Power’s revenue streams will also affect Operating Revenues and Energy Costs due to the application of this standard.
PSEG, PSE&G and Power do not anticipate any material impact to net income as a result of adoption of this new standard.
The new standard will result in more detailed disclosures of revenue compared to current guidance and changes in presentation. PSEG will disaggregate its revenues by operating segment. PSE&G will further disaggregate its revenue by product line (i.e. electric distribution, gas distribution, and transmission). Power will further disaggregate its revenues by product line (i.e. electricity, gas). Electricity revenues will be further disaggregated by region (i.e. PJM, New York ISO and ISO New England). Gas revenues will be further disaggregated by third party sales and sales to affiliates. Other Revenues from Contracts with Customers will also be disclosed including PSE&G appliance service and repair and Power solar power revenues.
PSEG will elect the invoice practical expedient, where applicable, in recording its revenue. Under the practical expedient, PSEG has a right to consideration from a customer in an amount that corresponds directly with the value to the customer of PSEG’s performance completed to date. PSEG may recognize revenue in the amount to which it has a right to invoice. As such under this practical expedient, there are no future performance obligations to disclose. Where PSEG has entered into fixed consideration contracts, it will disclose its remaining performance obligations under these agreements.
Recognition and Measurement of Financial Assets and Financial Liabilities
This accounting standard will change how entities measure equity investments that are not consolidated or accounted for under the equity method. Under the new guidance, equity investments (other than those accounted for using the equity method) will be measured at fair value through Net Income instead of Other Comprehensive Income (Loss). Entities that have elected the fair value option for financial liabilities will present changes in fair value due to a change in their own credit risk through Other Comprehensive Income (Loss). For equity investments which do not have readily determinable fair values, the impairment assessment will be simplified by requiring a qualitative assessment to identify impairments. The new standard also changes certain disclosures.
The standard is effective for annual and interim reporting periods beginning after December 15, 2017. PSEG recorded a cumulative effect adjustment by reclassifying the unrealized gain related to equity investments of $342 million ($176 million, net of tax) from Accumulated Other Comprehensive Income to Retained Earnings on January 1, 2018, and expects increased volatility in Net Income due to changes in fair value of its equity securities within the NDT and Rabbi Trust Funds.
Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments
This accounting standard reduces the diversity in practice in how certain cash receipts and cash payments are presented and classified in the Statement of Cash Flows.
The standard is effective for annual and interim periods beginning after December 15, 2017; early adoption was permitted. PSEG expects no changes in its presentation of its Statement of Cash Flows as a result of adopting this new standard. PSEG adopted this standard on January 1, 2018 using a retrospective transition method to each period presented.
Statement of Cash Flows: Restricted Cash
This accounting standard requires entities to explain the change during the period in the total of cash, cash equivalents and amounts generally described as restricted cash or restricted cash equivalents, either in a narrative or a tabular format. Amounts generally described as restricted cash or restricted cash equivalents should be included in entities’ reconciliation of beginning-of-period and end-of-period amounts in the Statement of Cash Flows.
The standard is effective for annual and interim periods beginning after December 15, 2017; early adoption was permitted. PSEG adopted this standard on January 1, 2018 using a retrospective transition method for each period presented. PSEG will

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continue the current balance sheet classification of restricted cash or restricted cash equivalents. PSEG will provide a reconciliation of cash and cash equivalents and restricted cash or restricted cash equivalents and include a description of these amounts.
Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (OPEB)
This accounting standard was issued to improve the presentation of net periodic pension cost and net periodic OPEB cost.
Under the new guidance, entities are required to report the service cost component in the same line item or items as other compensation costs arising from services rendered by their employees during the period. The other components of net benefit cost are required to be presented in the Statement of Operations separately from the service cost component after Operating Income. Additionally, only the service cost component will be eligible for capitalization, when applicable.
The standard requires the amendments to be applied retrospectively for the presentation of the service cost component and the other cost components of net periodic pension cost and net periodic OPEB cost in the Statement of Operations and prospectively, on and after the effective date, for the capitalization of the service cost component of net periodic pension and OPEB costs.
The standard is effective for annual and interim reporting periods beginning after December 15, 2017. PSEG adopted this standard as of January 1, 2018. Beginning January 1, 2018, PSEG and each of its subsidiaries began to classify the total net pension and OPEB non-service benefit costs in a separate line item in the Statement of Operations after Operating Income. PSEG will also recast those amounts for prior years in accordance with the new standard by using the practical expedient of using the previously disclosed non-service components of pension and OPEB costs. The service cost component of pension and OPEB costs will continue to be classified in O&M Expense, except for that portion capitalized, as appropriate, within Property, Plant and Equipment. As a result of adopting this new standard, PSE&G expects to reduce its charge to expense by approximately $55 million to $65 million in 2018.
Stock Compensation - Scope of Modification Accounting
This accounting standard provides clarity and reduces both diversity in practice and complexity when applying the stock compensation guidance to a change in the terms or conditions of a stock-based payment award. Specifically, the standard provides guidance as to which changes to the terms or conditions of a stock-based payment award require an entity to apply modification accounting.
The standard is effective for all entities for annual periods, and interim periods within those annual periods, beginning after December 15, 2017, early adoption was permitted. This standard should be applied prospectively to an award modified on or after the adoption date. PSEG adopted this standard effective January 1, 2018.
New Standards Issued But Not Yet Adopted
Leases
This accounting standard replaces existing lease accounting guidance and requires lessees to recognize all leases with a term greater than 12 months on the balance sheet using a right-of-use asset approach. At lease commencement, a lessee will recognize a lease asset and corresponding lease obligation. A lessee will classify its leases as either finance leases or operating leases based on whether control of the underlying assets has transferred to the lessee. A lessor will classify its leases as operating or direct financing leases, or as sales-type leases based on whether control of the underlying assets has transferred to the lessee. Both the lessee and lessor models require additional disclosure of key information. The standard requires lessees and lessors to apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. However, existing guidance related to leveraged leases will not change.
The standard is effective for annual and interim periods beginning after December 15, 2018 with retrospective application to previously issued financial statements for 2018 and 2017. Early application is permitted. PSEG is currently analyzing the impact of this standard on its financial statements.
Derivatives and Hedging: Targeted Improvements to Accounting for Hedging Activities
This accounting standard’s amendments more closely align hedge accounting with the companies’ risk management activities in the financial statements. The amendments expand hedge accounting for both non-financial and financial risk components by permitting contractually specified components to designate as the hedged risk in a cash flow hedge involving the purchase or sale of non-financial assets or variable rate financial instruments. Additionally, the amendments ease the operational burden of applying hedge accounting by allowing more time to prepare hedge documentation, and allow effectiveness assessments to be performed on a qualitative basis after hedge inception.

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The new guidance is effective for annual and interim periods beginning after December 15, 2018. The standard requires using a modified retrospective method upon adoption. Early adoption is permitted. PSEG is currently analyzing the impact of this standard on its consolidated financial statements. 
Premium Amortization on Purchased Callable Debt Securities
This accounting standard was issued to shorten the amortization period for certain callable debt securities held at a premium. Specifically, the standard requires the premium to be amortized to the earliest call date. The amendments do not require an accounting change for securities held at a discount; the discount continues to be amortized to maturity.
The standard is effective for annual and interim reporting periods beginning after December 15, 2018. Early adoption is permitted for an entity in any interim or annual period. If an entity early adopts the standard in an interim period, any
adjustments should be reflected as of the beginning of the fiscal year that includes that interim period. An entity should apply this standard on a modified retrospective basis through a cumulative-effect adjustment directly to retained earnings as of the beginning of the period of adoption. Additionally, in the period of adoption, an entity should provide disclosures about a change in accounting principle. PSEG is currently analyzing the impact of this standard on its financial statements.
Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income
This accounting standard would affect any entity that is required to apply the provisions of the Accounting Standards Codification topic, “Income Statement-Reporting Comprehensive Income,” and has items of other comprehensive income for which the related tax effects are presented in other comprehensive income as required by GAAP. Specifically, this standard would allow entities to record a reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the newly enacted federal corporate income tax rate. The amount of the reclassification would be the difference between the historical corporate income tax rate and the newly enacted 21% corporate income tax rate.
The standard is effective for all entities for annual periods, and interim periods within those annual periods beginning after December 15, 2018. Early adoption is permitted for an entity in any interim or annual period for public business entities for reporting periods for which financial statements have not yet been issued or made available for issuance.
An entity would be able to choose to apply this standard retrospectively to each period (or periods) in which the effect of the change in the U.S. federal corporate income tax rate in the new tax legislation enacted in 2017 is recognized or apply the standard in the reporting period adopted. PSEG is currently analyzing the impact this standard, if adopted, could have on its consolidated financial statements.
Measurement of Credit Losses on Financial Instruments—Accounting Standards Update (ASU) 2016-13, updated by ASU 2018-19, 2019-04, 2019-05, 2019-11 and 2020-02
This accounting standard provides a new model for recognizing credit losses on financial assets carried at amortized cost.assets. The new model requires entities to use an estimate of expected credit losses that will be recognized as an impairment allowance rather than a direct write-down of the amortized cost basis. The estimate of expected credit losses is to be based on past events, current conditions and supportable forecasts over a reasonable period. For purchased financial assets with credit deterioration, a similar model is to be used;
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however, the initial allowance will beis added to the purchase price rather than reported as an allowance. Credit losses on available-for-sale debt securities should beare measured in a manner similar to current GAAP; however, this standard requires those credit losses to be presented as an allowance, rather than a write-down. This new standard also requires additional disclosures of the allowance for credit losses by financial asset type, including disclosures of credit quality indicators for each class of financial asset disaggregated by year of origination.
The standard was effective for annual and interim periods beginning after December 15, 2019. PSEG adopted this standard on January 1, 2020 on a modified retrospective basis. Upon adoption, PSE&G recorded an increase of $8 million to its allowance for credit losses, offset by a $6 million increase to Regulatory and Other Assets, and a $2 million cumulative effect charge to Retained Earnings. See Note 3. Revenues. There was no impact from adoption of this standard on the financial statements of PSEG Power.
Disclosure Framework—Changes to the Disclosure Requirements for Fair Value Measurement—ASU 2018-13
This accounting standard modifies the disclosure requirements for fair value measurements. Certain current disclosure requirements relating to Level 3 fair value measurements, and transfers between Level 1 and Level 2 fair value measurements have been eliminated. The standard also adds certain other disclosure requirements for Level 3 fair value measurements.
The standard was effective for annual and interim periods beginning after December 15, 2019. PSEG adopted this standard on January 1, 2020. Certain amendments in the standard have been applied prospectively in 2020. All other amendments of the standard were applied retrospectively to all periods presented.
Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract—ASU 2018-15
This accounting standard aligns the capitalization requirements for implementation costs incurred in a hosting arrangement that is a service contract with capitalization requirements for implementation costs incurred to develop or obtain internal-use software, including hosting arrangements that include an internal-use software license. The standard follows the guidance in Accounting Standard Codification 350—Intangibles—Goodwill and Other to determine which implementation costs to capitalize as an asset related to the service contract and which costs to expense. The standard requires the amortization of capitalized costs to be presented in O&M Expense. In addition, the standard also adds presentation requirements for these costs in the statements of cash flows and financial position.
The standard was effective for annual and interim periods beginning after December 15, 2019. PSEG adopted this standard prospectively on January 1, 2020. Adoption of this standard did not have a material impact on the financial statements of PSEG, PSE&G and PSEG.
Targeted Improvements to Related Party Guidance for Variable Interest Entities (VIE)—ASU 2018-17
This accounting standard improves the VIE guidance in the area of decision-making fees. Consistent with how indirect interests held through related parties under common control are considered for determining whether a reporting entity must consolidate a VIE, indirect interests held through related parties in common control arrangements are considered on a proportional basis for determining whether fees paid to decision makers and service providers are variable interests.
This standard is effective for annual and interim periods beginning after December 15, 2019; however, entities may adopt early2019. The standard is required to be applied retrospectively with a cumulative effect adjustment to Retained Earnings at the beginning inof the annual or interim periods after December 15, 2018.earliest period presented. PSEG is currently analyzing the impactadopted this standard on January 1, 2020. Adoption of this standard did not have an impact on itsthe financial statements.statements of PSEG, PSE&G and PSEG Power.
Simplifying the Test for Goodwill Impairment—ASU 2017-04
This accounting standard requires an entity to perform its annual or interim goodwill impairment test by comparing the fair value of a reporting unit with its carrying amount. An entity should recognize an impairment charge for the amount by which the carrying amount exceeds the reporting unit’s fair value; however, the loss recognized should not exceed the total amount of goodwill allocated to that reporting unit. Additionally, an entity should consider income tax effects from any tax deductible goodwill on the carrying amount of the reporting unit when measuring the goodwill impairment loss, if applicable.
An entity should apply thisThis standard requires application on a prospective basis and will be required to disclose the nature of and reason for the change in accounting principle upon transition.basis. The new standard iswas effective for impairment tests for periods beginning January 1, 2020. Early adoption is permittedPSEG early adopted this standard in the fourth quarter of 2019, and recorded an impairment loss of $16 million in O&M Expense.
Codification Improvements to Financial Instruments—ASU 2020-03
This accounting standard provides clarification of guidance for interim or annual goodwill impairment tests performed on testing dates after January 1, 2017.financial instruments and makes narrow scope amendments related to various issues. PSEG is currently assessingadopted this standard in the impactfirst quarter of 2020. Adoption of this guidance upon itsstandard did not have an impact on the financial statements.

statements of PSEG, PSE&G and PSEG Power.
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Note 3. Early Plant Retirements
Fossil
In October 2016, Power determined that it would cease generation operationsFacilitation of the existing coal/gas units atEffects of Reference Rate Reform on Financial Reporting—ASU 2020-04
This accounting standard provides optional expedients and exceptions for applying GAAP to contract modifications and hedging relationships, subject to meeting certain criteria, that reference London Interbank Offered Rate (LIBOR) or another reference rate expected to be discontinued. The standard was effective from its issuance date, March 12, 2020, through December 31, 2022. PSEG adopted this standard effective upon issuance. Adoption of this standard did not have an impact on the Hudsonfinancial statements of PSEG, PSE&G and Mercer generating stationsPSEG Power.
Disclosure Framework—Changes to the Disclosure Requirements for Defined Benefit Plans—ASU 2018-14
This accounting standard modifies the disclosure requirements for employers that sponsor defined benefit pension or other postretirement plans, including the elimination of certain current disclosure requirements. Certain other disclosure requirements related to interest crediting rates have been added and certain clarifications were made to other disclosure requirements.
The standard is effective for fiscal years ending after December 15, 2020 and early adoption is permitted. Amendments in this standard will be applied on June 1, 2017. Both units were availablea retrospective basis to operate through Mayall periods presented. PSEG adopted this standard on December 31, 20172020. The amendments in the standard have been applied retrospectively to all periods presented. SeeNote 14. Pension, Other Postretirement Benefits (OPEB) and were subsequently retired from operation on June 1, 2017.Savings Plans.
New Standards Issued But Not Yet Adopted As of December 31, 2017,2020
Simplifying the retirementsAccounting for Income Taxes—ASU 2019-12
This accounting standard updates ASC 740 to simplify the accounting for income taxes, including the elimination of both unitsseveral 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 and early adoption is permitted. Amendments will be applied either on a retrospective, modified retrospective through a cumulative adjustment to Retained Earnings in the year of adoption, or on a prospective basis. PSEG adopted this standard on January 1, 2021. PSEG will be electing to allocate the consolidated tax expense to all eligible entities that are included in a consolidated tax filing. Making this election will be consistent with PSEG’s Tax Sharing Agreements with its affiliated subsidiaries, as stated in Note 1. Organization, Basis of Presentation and Summary of Significant Accounting Policies. Adoption of this standard did not have an impact on the financial statements of PSEG, PSE&G, and PSEG Power.
Clarifying the Interactions between Investments-Equity Securities, Investments-Equity Method and Joint Ventures, and Derivatives and Hedging—ASU 2020-01
This accounting standard clarifies that an entity should consider transaction prices for purposes of measuring the fair value of certain equity securities immediately before applying or upon discontinuing the equity method. This accounting standard also clarifies that when accounting for contracts entered into to purchase equity securities, an entity should not consider whether, upon the settlement of the forward contract or exercise of the purchased option, the underlying securities would be accounted for under the equity method or the fair value option.
The standard is effective for fiscal years beginning after December 15, 2020. Amendments in this standard will be applied prospectively. PSEG adopted this standard on January 1, 2021. Adoption of this standard did not have an impact on the financial statements of PSEG, PSE&G and PSEG Power.
Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity—ASU 2020-06
This accounting standard simplifies the accounting for convertible debt and convertible preferred stock by removing the requirements to separately present certain conversion features in equity. In addition, the ASU eliminates certain criteria that must be satisfied in order to classify a contract as equity, which is expected to decrease the number of freestanding instruments and embedded derivatives accounted for as assets or liabilities. The ASU also revises the guidance on calculating earnings per share, requiring use of the if-converted method for all convertible instruments and rescinding the ability to rebut the presumption of share settlement for instruments that may be settled in cash or other assets.
The standard is effective for fiscal years beginning after December 15, 2020. Amendments in this standard will be applied on either a retrospective basis for all periods presented or a modified retrospective basis through a cumulative effect adjustment to Retained Earnings as of the beginning of the fiscal year of adoption. Early adoption is permitted. PSEG adopted this standard on January 1, 2021. Adoption of this standard did not have an impact on the financial statements of PSEG, PSE&G and PSEG Power.
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Codification Improvements to Callable Debt Securities—ASU 2020-08
This accounting standard clarifies that an entity should reevaluate for each reporting period whether a purchased callable debt security that has multiple call dates is within the scope of certain guidance on nonrefundable fees and other costs related to receivables.
The standard is effective for fiscal years beginning after December 15, 2020 and early adoption is not permitted. Amendments in this standard will be applied prospectively. PSEG adopted this standard on January 1, 2021. Adoption of this standard did not have an impact on the financial statements of PSEG, PSE&G and PSEG Power.
Amendments to SEC Guidance in the Codification—ASU 2020-09
This accounting standard aligns the SEC guidance in the codification with the SEC rules issued in March 2020 relating to changes in the disclosure requirements for certain debt securities. Certain glossary terms were substantially complete.superseded and amendments were made to debt and other topics as a result of this update.
The standard is effective on January 4, 2021 and early adoption is permitted. PSEG adopted the new SEC rules earlier in 2020 and has eliminated the footnote relating to the guarantors of debt, and now presents summarized Guarantor Financial Information in Item 7. Liquidity and Capital Resources.
Codification Improvements—ASU 2020-10
This accounting standard conforms, clarifies, simplifies, and provides technical corrections to various codification topics.
The standard is effective for fiscal years beginning after December 15, 2020 and early adoption is permitted. PSEG adopted this standard on January 1, 2021. Adoption of this standard did not have an impact on the financial statements of PSEG, PSE&G and PSEG Power.
Reference Rate Reform Scope Refinement—ASU 2021-01
This accounting standard clarifies certain guidance related to derivative instruments affected by the market-wide change in the interest rates even if those derivatives do not reference the LIBOR or another rate that is expected to be discontinued as a result of reference rate reform. The accounting standard also clarifies other aspects of the relief provided in the reference rate reform GAAP guidance.
The standard is effective upon issuance and allows for retrospective or prospective application with certain conditions. PSEG adopted this standard in January 2021. Adoption of this standard did not have an impact on the financial statements of PSEG, PSE&G and PSEG Power.
Note 3. Revenues
Nature of Goods and Services
The following is a description of principal activities by reportable segment from which PSEG, PSE&G and PSEG Power 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.
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
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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 weather normalization, green energy program true-ups and transmission formula rate true-ups, are not a material source of PSE&G revenues.
PSEG Power
Revenues from Contracts with Customers
Electricity and Related Products—Wholesale and retail load contracts are executed in the different Independent System Operator (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 Power 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 latter halfBPU. 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. 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 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 2016,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.
Other Revenues from Contracts with Customers
PSEG Power enters into bilateral contracts to sell solar power and solar RECs from its solar facilities. Contract terms range from 15 to 30 years. The performance obligations are generally solar power and RECs which are transferred to customers upon generation. Revenue is recognized pre-tax chargesupon generation of the solar power.
PSEG Power has entered into long-term contracts with LIPA for energy management and fuel procurement services. Revenue is recognized over time as services are rendered.
Revenues Unrelated to Contracts with Customers
PSEG Power’s revenues unrelated to contracts with customers include electric, gas and certain energy-related transactions accounted for in accordance with Derivatives and Hedging accounting guidance. See Note 18. Financial Risk Management Activities for further discussion. PSEG Power is also a party to solar contracts that qualify as leases and are accounted for in accordance with lease accounting guidance.
Other
Revenues from Contracts with Customers
PSEG LI has a contract with LIPA which generates revenues. PSEG LI’s subsidiary, Servco records costs which are recovered from LIPA and records the recovery of those costs as revenues when Servco is a principal in the transaction.
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Revenues Unrelated to Contracts with Customers
Energy CostsHoldings generates lease revenues which are recorded pursuant to lease accounting guidance.
Disaggregation of Revenues
PSE&GPSEG PowerOther EliminationsConsolidated
Millions
Year Ended December 31, 2020
Revenues from Contracts with Customers
Electric Distribution$3,130 $0 $0 $0 $3,130 
Gas Distribution1,646 0 0 (12)1,634 
Transmission1,485 0 0 0 1,485 
Electricity and Related Product Sales
PJM
Third-Party Sales0 1,551 0 0 1,551 
Sales to Affiliates0 447 0 (447)0 
NY-ISO0 124 0 0 124 
ISO-NE0 126 0 0 126 
Gas Sales
Third-Party Sales0 83 0 0 83 
Sales to Affiliates0 771 0 (771)0 
Other Revenues from Contracts with Customers (A)338 45 587 (4)966 
Total Revenues from Contracts with Customers6,599 3,147 587 (1,234)9,099 
Revenues Unrelated to Contracts with Customers (B)9 487 8 0 504 
Total Operating Revenues$6,608 $3,634 $595 $(1,234)$9,603 
PSE&GPSEG PowerOther EliminationsConsolidated
Millions
Year Ended December 31, 2019
Revenues from Contracts with Customers
Electric Distribution$3,224 $0 $0 $0 $3,224 
Gas Distribution1,870 0 0 (15)1,855 
Transmission1,181 0 0 0 1,181 
Electricity and Related Product Sales
 PJM
Third-Party Sales0 1,785 0 0 1,785 
         Sales to Affiliates0 536 0 (536)0 
NY-ISO0 143 0 0 143 
ISO-NE0 137 0 0 137 
Gas Sales
Third-Party Sales0 92 0 0 92 
Sales to Affiliates0 927 0 (927)0 
Other Revenues from Contracts with Customers (A)284 46 566 (5)891 
Total Revenues from Contracts with Customers6,559 3,666 566 (1,483)9,308 
Revenues Unrelated to Contracts with Customers (B)66 719 (17)0 768 
Total Operating Revenues$6,625 $4,385 $549 $(1,483)$10,076 
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PSE&GPSEG PowerOther EliminationsConsolidated
Millions
Year Ended December 31, 2018
Revenues from Contracts with Customers
Electric Distribution$3,131 $0 $0 $0 $3,131 
Gas Distribution1,756 0 0 (18)1,738 
Transmission1,236 0 0 0 1,236 
Electricity and Related Product Sales
 PJM
Third-Party Sales0 1,933 0 0 1,933 
         Sales to Affiliates0 609 0 (609)0 
NY-ISO0 209 0 0 209 
ISO-NE0 92 0 0 92 
Gas Sales
Third-Party Sales0 151 0 0 151 
Sales to Affiliates0 861 0 (861)0 
Other Revenues from Contracts with Customers (A)275 44 532 (4)847 
Total Revenues from Contracts with Customers6,398 3,899 532 (1,492)9,337 
Revenues Unrelated to Contracts with Customers (B)73 247 39 0 359 
Total Operating Revenues$6,471 $4,146 $571 $(1,492)$9,696 
(A)Includes primarily revenues from appliance repair services at PSE&G, solar power projects and O&Menergy management and fuel service contracts with LIPA at PSEG Power, and PSEG LI’s OSA with LIPA in Other.
(B)Includes primarily alternative revenues at PSE&G, derivative contracts and lease contracts at PSEG Power, and lease contracts in Other. For the years ended December 31, 2020, 2019 and 2018, Other includes losses of $62$26 million, $58 million and $53$8 million, respectively, related to coal inventory adjustments, capacity penalties, materials and supplies inventory reserve adjustmentsEnergy 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 parts that cannot be used at other generating units, employee-related severance benefits costs and construction workservices already provided or obligations to provide services in progress impairments, among other shut down items. In addition to these charges, Power recognized Depreciation and Amortization (D&A) during 2016the future for consideration already received) as of $571 million due to the significant shortening of the expected economic useful lives of Hudson and Mercer.
As of June 1, 2017, Power recognized total D&A of $964 million for the Hudson and Mercer units to reflect the end of their economic useful lives in 2017. During the year ended December 31, 2017, Power recognized pre-tax charges2020 and 2019. 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 14% and 6% of accounts receivable (including unbilled revenues in Energy Costs2020) as of $15 million, primarily for coal inventory lower of cost or market adjustments. During the year ended December 31, 2017, Power also recognized pre-tax charges in O&M of $23 million, including shut down costs2020 and an increase in the Asset Retirement Obligation due to settlements and changes in cash flow estimates, partially offset by changes in employee-related severance costs. Power is exploring various opportunities with these sites, including using the sites for alternative industrial activity or the disposition of one or both of the sites. If Power determines not to use the sites for alternative industrial activity, the early retirement of the units at such sites would trigger obligations under certain environmental regulations, including possible remediation. The amounts for any such environmental remediation are neither currently probable nor estimable but may be material.
2019, respectively. As of December 31, 2016,2019, there was no allowance for unbilled revenues. Effective January 1, 2020, PSE&G adopted ASU 2016-13 and recorded an allowance for unbilled revenues. See Note 2. Recent Accounting Standards.
The following provides a reconciliation of PSE&G’s allowance for credit losses for the years ended December 31, 2020 and 2019. 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 outstanding balances as of December 31, 2020. PSE&G’s electric bad debt expense is recoverable through its Societal Benefits Clause mechanism. As of December 31, 2020, 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.
Years Ended December 31,
20202019
Millions
Balance at Beginning of Year$68 (A)$63 
Utility Customer and Other Accounts
     Provision175 87 
     Write-offs, net of Recoveries of $5 million and $8 million(37)(90)
Balance at End of Year$206 $60 
(A)Includes an $8 million pre-tax increase upon adoption of ASU 2016-13.     
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PSEG Power
PSEG Power generally collects consideration upon satisfaction of performance obligations, and therefore, PSEG Power had reducedno material contract balances as of December 31, 2020 and 2019.
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 estimated useful lifeConsolidated 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, 2020. PSEG Power monitors the status of its counterparties on an ongoing basis to assess whether there are any anticipated credit losses.
Other
PSEG LI does not have any material contract balances as of December 31, 2020 and 2019.
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:
PSEG Power
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 has yet to be held and is not expected until mid-2021. 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
June 2020 to May 2021$1677,600 
June 2021 to May 2022$1807,000 
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 $231/MW-day for seven years, and the planned retirement of Bridgeport Harbor Station unit 3 (BH3) in May 2021. PSEG Power expects to realize the following average capacity prices for capacity obligations to be satisfied resulting from the FCM Auctions which have been completed through May 2024 and the seven-year rate lock for BH5 through May 2026:
Delivery Year$ per MW-Day (A)MW Cleared
June 2020 to May 2021$1951,330 
June 2021 to May 2022$192950 
June 2022 to May 2023$179950 
June 2023 to May 2024$152930 
June 2024 to May 2025$231480 
June 2025 to May 2026$231480 
(A)Capacity cleared prices for BH5 through 2026 will be escalated based upon the Handy-Whitman Index. These adjustments are not included above.    
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Bilateral capacity contracts—Capacity obligations pursuant to contract terms through 2029 are anticipated to result in revenues totaling $146 million.
Other
The LIPA OSA is a 12-year services contract ending in 2025 towith annual fixed and incentive components. The fixed fee for the summerprovision of services thereunder in 2021 as it was more likely than not it will retireis $68 million and is updated each year based on the unit by this time.
PSEG and Power continue to monitor their other coal assets, including the Keystone and Conemaugh generating stations, to assess their economic viability through the end of their designated useful lives and their continued classification as held for use. The precise timing of a change in useful lives may be dependent upon events out of PSEG’s and Power’s control and may impact their ability to operate or maintain certain assets in the future. These generating stations may be impacted by factors such as environmental legislation, co-owner capital requirements and continued depressed wholesale power prices or capacity factors, among other things. Any early retirement or change in the held for use classification of our remaining coal units may have a material adverse impact on PSEG’s and Power’s future financial results.Consumer Price Index (CPI).
Note 4. Early Plant Retirements/Asset Dispositions
Nuclear
Since 2013, severalIn April 2019, PSEG Power’s Salem 1, Salem 2 and Hope Creek nuclear generating stationsplants 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 United States have closedamount of $0.004 per kilowatt-hour (KWh) used (which is equivalent to approximately $10 per megawatt hour (MWh) generated in payments to selected nuclear plants (ZEC payment)). These nuclear plants are expected to receive ZEC revenue for approximately three years, through May 2022, and will be obligated to maintain operations during that period, subject to 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. The ZEC payment may be adjusted by the BPU (a) at any time to offset environmental or announced earlyfuel diversity payments that a selected nuclear plant may receive from another source or (b) at certain times specified in the ZEC legislation if the BPU determines that the purposes of the ZEC legislation can be achieved through a reduced charge that will nonetheless be sufficient to achieve the state’s air quality and other environmental objectives by preventing the retirement dueof nuclear plants. For instance, the New Jersey Rate Counsel, in written comments filed with the BPU, has advocated for the BPU to economic reasons,offset market benefits resulting from New Jersey’s rejoining the Regional Greenhouse Gas Initiative from the ZEC payment. PSEG intends to vigorously defend against these arguments. Due to its preliminary nature, PSEG cannot predict the outcome of this matter.
The BPU’s decision awarding ZECs has been appealed by the New Jersey Rate Counsel. PSEG cannot predict the outcome of this matter.
In October 2020, PSEG Power filed with the BPU its ZEC applications for Salem 1, Salem 2 and Hope Creek for the three-year eligibility period starting in June 2022. No other plants applied for ZECs for this eligibility period. PSEG Power is not aware of any changes from its ZEC application for the first eligibility period that would materially affect its ability to establish eligibility to be awarded ZECs during the second eligibility period. A final BPU decision is expected in April 2021. PSEG cannot predict the outcome of this matter.
In the event that (i) the ZEC program is overturned or have announced being at risk for early retirement. Most recently,is otherwise materially adversely modified through legal process; (ii) the amount of ZEC payments that may be awarded or other terms and conditions of the second ZEC eligibility period proposed by the BPU in February 2018, Exelon, a co-ownerits final decision differ from those of the current ZEC period; or (iii) any of the Salem units, announced its intention to accelerate the closure of its Oyster1, Salem 2 and Hope Creek nuclear plant located in New Jersey, one year earlier than previously planned for economic reasons. These closures and retirements are generally due to the decline in market prices of energy, resulting from low natural gas prices drivenplants is not awarded ZEC payments by the growthBPU and does not otherwise experience a material financial change, PSEG Power will take all necessary steps to cease to operate all of shale gas production since 2007, the continuing cost of regulatory compliance and enhanced security for nuclear facilities, both federal and state-level policies that provide financial incentives to construct renewable energy such as wind and solar and the failure to adequately compensate nuclear generating stations for the attributes they bring similar to renewable energy production. These trends have significantly reduced the revenues of nuclear generating stations while limiting their ability to reduce the unit cost of production. This may result in the electric generation industry experiencing a further shift from nuclear generation to natural gas-fired generation, creating less diversity of the generation fleet.
If any orthese plants. Alternatively, if all of the Salem 1, Salem 2 and Hope Creek units were shut down, it would significantly alter New Jersey’s energy supply predominatelyplants are selected to continue to receive ZEC payments but the financial condition of the plants is materially adversely impacted by increasing New Jersey’s reliance on natural gas generation. Suchchanges in commodity prices, FERC’s changes to the capacity market construct (absent sufficient capacity revenues provided under a decreaseprogram approved by the BPU in fuel diversity could also increase the market’s vulnerability to price fluctuations and power disruptions in times of high demand. The New Jersey Legislature is assessing legislation that would provideaccordance with a safety net in order to prevent the loss of environmental attributes from nuclear generating stations. Power cannot predict whether the legislation will be enactedFERC-authorized capacity mechanism), or, if enacted, whether our nuclear generating stations in New Jersey will be selected or whether the legislation will provide a sufficient safety net for the continued operation of nuclear generating stations in New Jersey.
In the ordinary course, management, and in the case of the Salem units the co-owner, each makes a number ofnuclear plants, decisions that impact the operation of our nuclear units beyond the current year, including whether and to what extent these units participate in RPM capacity auctions, commitments relating to refueling outages and significant capital expenditures, and decisions regarding our hedging arrangements. When considering whether to make these future commitments, management’s decisions will primarily be

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influenced by the financial outlookEPA and state environmental regulators regarding the implementation of Section 316(b) of the units, including the progress, timingClean Water Act (CWA) and continued outlook for enactmentrelated state regulations, or other factors, PSEG Power will take all necessary steps to cease to operate all of proposed legislation in the state of New Jersey.
If market prices continue to be depressedthese plants and legislation is not enacted that adequately compensates nuclear generating stations for their attributes, Power anticipates it will no longer be covering itsincur associated costs nor be adequately compensated for its market and operational risks at the Salem and Hope Creek nuclear units and would anticipate retiring these units early. The costs associated with any such retirement, whichaccounting charges. These may include, among other things, accelerated depreciation and amortization orone-time impairment charges or accelerated D&A Expense on the remaining carrying value of the plants, potential penalties associated with the early termination of capacity obligations and fuel contracts, accelerated asset retirement costs, severance costs, environmental remediation costs and, in certain circumstances potential additional funding of the Nuclear Decommissioning TrustNDT Fund, (NDT)which would be material to both PSEG and PSEG Power.
Non-Nuclear
In July 2020, PSEG announced that it is exploring strategic alternatives for PSEG Power’s non-nuclear generating fleet, which includes more than 6,750 MW of fossil generation located in New Jersey, Connecticut, New York and Maryland as well as the 467 MW Solar Source portfolio located in various states. PSEG intends to retain ownership of PSEG Power’s existing nuclear fleet. The following table providesmarketing of a potential transaction in one or a series of steps launched in the balance sheet amounts byfourth quarter of 2020, and any potential transaction is expected to be completed sometime in 2021. As a result of the strategic review of PSEG Power’s non-nuclear generating stationassets, and the launch in the fourth quarter of 2020 of an associated marketing process for their potential disposition, PSEG Power performed an impairment assessment of its PJM, NYISO and ISO-NE asset groupings, as well as for
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its solar assets, as of September 30, 2020 and December 31, 2020. The assessments included probability weightings assigned to undiscounted cash flow scenarios of retaining the assets through the end of their estimated useful lives and a successful disposition of the non-nuclear assets in 2021. Estimates of cash flows associated with a sale scenario were based on management’s expectations of the fair value of such assets. The probability weighted aggregation of undiscounted cash flows for each of the asset groupings expected to result from the use and potential disposition of the asset groups exceeded their carrying value at the above mentioned September 30, 2020 and December 31, 2020 assessment dates. As such, it demonstrated that no impairment exists for any of the asset groupings and they continue to remain classified as held-for-use as of December 31, 2017 for significant2020. However, certain assumptions are subject to change as the potential sales and marketing process progresses. The carrying value of the fossil generation and of the solar assets (net of eligible investment tax credits (ITC)) was $4.5 billion and $560 million, respectively, as of December 31, 2020.
There is no assurance that the strategic review will result in a sale or other disposition of all or any portion of these assets on terms that are favorable to us, or at all. Any transaction would be subject to market conditions and customary closing conditions, including the receipt of all required regulatory approvals. Management expects that a change in the probability of a successful disposition based upon further progression in the marketing process, but prior to meeting all necessary held-for-sale classification criteria, would result in an impairment of the ISO-NE asset grouping, which would be material. Furthermore, a change to a held-for-sale classification from a held-for-use classification would result in an impairment of the PJM, NYISO and ISO-NE asset groupings, which would be material.
In September 2020, PSEG Power completed the sale of its ownership interest in the Yards Creek generation facility. PSEG Power recorded a pre-tax gain on disposition of approximately $122 million in the third quarter of 2020 as the sale price was greater than book value.
In September 2019, PSEG Power completed the sale of its ownership interests in the Keystone and Conemaugh generation plants and related assets and liabilities. PSEG Power recorded a pre-tax loss on disposition of approximately $400 million in the second quarter of 2019 as the sale price was less than book value.
In December 2018, PSEG Power completed the sale of the sites of the retired Hudson and Mercer units. PSEG Power transferred all land rights and structures on the sites to a third-party purchaser, along with the assumption of the environmental liabilities associated with Power’s owned sharefor the sites. As a result of its nuclear assets.the sale and transfer of liabilities, PSEG Power recorded a pre-tax gain in 2018 of $54 million.
           
   As of December 31, 2017 
   Hope Creek Salem Support Facilities and Other (A) Peach Bottom 
   Millions 
 Assets         
 Materials and Supplies Inventory $86
 $78
 $—
 $41
 
 Nuclear Production, net of Accumulated Depreciation 605
 661
 211
 802
 
 Nuclear Fuel In-Service, net of Accumulated Depreciation 104
 124
 —
 153
 
 Construction Work in Progress (including nuclear fuel) 245
 90
 1
 25
 
         Total Assets $1,040
 $953
 $212
 $1,021
 
 Liabilities         
 Asset Retirement Obligation $302
 $249
 $—
 $205
 
         Total Liabilities $302
 $249
 $—
 $205
 
          Net Assets $738
 $704
 $212
 $816
 
 NRC License Renewal Term 2046 2036/2040
 N/A
 2033/2034
 
 % Owned 100% 57% Various
 50% 
           
(A)Includes Hope Creek’s and Salem’s shared support facilities and other nuclear development capital.
The precise timing of any potential early retirement and resulting financial statement impact may be affected by a number of factors, including co-owner considerations, the results of any transmission system reliability study assessments and decommissioning trust fund requirements and other commitments, as well as future energy prices. Power maintains a NDT Fund that funds its decommissioning obligations. See Note 9. Available-for-Sale Securities.
Note 4.5. Variable Interest Entity (VIE)
VIE for which PSEG LI is the Primary Beneficiary
PSEG LI consolidates Long Island Electric Utility Servco, LLC (Servco), a marginally capitalized VIE, which was created for the purpose of operating LIPA’s T&D system in Long Island, New York as well as providing administrative support functions to LIPA. PSEG LI is the primary beneficiary of Servco because it directs the operations of Servco, the activity that most significantly impacts Servco’s economic performance and it has the obligation to absorb losses of Servco that could potentially be significant to Servco. Such losses would be immaterial to PSEG.
Pursuant to the OSA, Servco’s operating costs are reimbursablepaid entirely by LIPA, and therefore, PSEG LI’s risk is limited related to the activities of Servco. PSEG LI has no current obligation to provide direct financial support to Servco. In addition to reimbursementpayment of Servco’s operating costs as provided for in the OSA, PSEG LI receives an annual contract management fee. PSEG LI’s annual contractual management fee, in certain situations, could be partially offset by Servco’s annual storm costs not approved by the Federal Emergency Management Agency, limited contingent liabilities and penalties for failing to meet certain performance metrics.
For transactions in which Servco acts as principal and controls the services provided to LIPA, such as transactions with its employees for labor and labor-related activities, including pension and OPEB-related transactions, Servco records revenues and the related pass-through expenditures separately in Operating Revenues and O&M Expense, respectively. In 2017, 20162020, 2019 and 2015,2018, Servco recorded $438$520 million, $410$490 million

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and $375$458 million, respectively, of O&M costs, the full reimbursement of which was reflected in Operating Revenues.costs. For transactions in which Servco acts as an agent for LIPA, it records revenues and the related expenses on a net basis, resulting in no impact on PSEG’s Consolidated Statement of Operations.
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Note 5.6. Property, Plant and Equipment and Jointly-Owned Facilities
Information related to Property, Plant and Equipment as of December 31, 20172020 and 20162019 is detailed below:
PSE&GPSEG PowerOtherPSEG
Consolidated
 Millions
2020
Transmission and Distribution:
Electric Transmission$14,075 $0 $0 $14,075 
Electric Distribution9,622 0 0 9,622 
Gas Distribution and Transmission9,081 0 0 9,081 
Construction Work in Progress1,783 0 0 1,783 
Other659 0 0 659 
Total Transmission and Distribution35,220 0 0 35,220 
Generation:
Fossil Production0 6,581 0 6,581 
Nuclear Production0 3,296 0 3,296 
Nuclear Fuel in Service0 748 0 748 
Other Production-Solar658 911 0 1,569 
Construction Work in Progress0 248 0 248 
Total Generation658 11,784 0 12,442 
Other422 88 397 907 
Total$36,300 $11,872 $397 $48,569 
          
  PSE&G Power Other 
PSEG
Consolidated
 
  Millions 
 2017        
 Transmission and Distribution:        
 Electric Transmission$10,425
 $—
 $—
 $10,425
 
 Electric Distribution8,455
 —
 —
 8,455
 
 Gas Distribution and Transmission7,122
 —
 —
 7,122
 
 Construction Work in Progress1,735
 —
 —
 1,735
 
 Other512
 —
 —
 512
 
 Total Transmission and Distribution28,249
 —
 —
 28,249
 
 Generation:        
 Fossil Production—
 4,923
 —
 4,923
 
 Nuclear Production—
 2,893
 —
 2,893
 
 Nuclear Fuel in Service—
 745
 —
 745
 
 Other Production-Solar593
 757
 —
 1,350
 
 Construction Work in Progress—
 2,339
 —
 2,339
 
 Total Generation593
 11,657
 —
 12,250
 
 Other275
 98
 359
 732
 
 Total$29,117
 $11,755
 $359
 $41,231
 
          
PSE&GPSEG PowerOtherPSEG
Consolidated
 Millions
2019
Transmission and Distribution:
Electric Transmission$12,908 $0 $0 $12,908 
Electric Distribution9,255 0 0 9,255 
Gas Distribution and Transmission8,430 0 0 8,430 
Construction Work in Progress1,607 0 0 1,607 
Other639 0 0 639 
Total Transmission and Distribution32,839 0 0 32,839 
Generation:
Fossil Production0 6,570 0 6,570 
Nuclear Production0 3,087 0 3,087 
Nuclear Fuel in Service0 761 0 761 
Other Production-Solar663 911 0 1,574 
Construction Work in Progress0 277 0 277 
Total Generation663 11,606 0 12,269 
Other398 93 345 836 
Total$33,900 $11,699 $345 $45,944 
           
   PSE&G Power Other 
PSEG
Consolidated
 
   Millions 
 2016         
 Transmission and Distribution:         
 Electric Transmission $9,149
 $—
 $—
 $9,149
 
 Electric Distribution 7,976
 —
 —
 7,976
 
 Gas Distribution and Transmission 6,458
 —
 —
 6,458
 
 Construction Work in Progress 1,501
 —
 —
 1,501
 
 Other 439
 —
 —
 439
 
 Total Transmission and Distribution 25,523
 —
 —
 25,523
 
 Generation:         
 Fossil Production —
 7,096
 —
 7,096
 
 Nuclear Production —
 2,516
 —
 2,516
 
 Nuclear Fuel in Service —
 783
 —
 783
 
 Other Production-Solar 591
 687
 —
 1,278
 
 Construction Work in Progress —
 1,483
 —
 1,483
 
 Total Generation 591
 12,565
 —
 13,156
 
 Other 233
 90
 335
 658
 
 Total $26,347
 $12,655
 $335
 $39,337
 
           

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PSE&G and PSEG Power have ownership interests in and are responsible for providing their respective shares of the necessary financing for the following jointly-owned facilities to which they are a party. All amounts reflect PSE&G’s or PSEG Power’s share of the jointly-owned projects and the corresponding direct expenses are included in the Consolidated Statements of Operations as operating expenses.Operating Expenses.
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     As of December 31, 
     2017 2016 
   Ownership   Accumulated   Accumulated 
   Interest Plant Depreciation Plant Depreciation 
     Millions 
 PSE&G:           
 Transmission Facilities Various
 $162
 $58
 $169
 $65
 
 Power:           
 Coal Generating:           
 Conemaugh 23% $408
 $178
 $408
 $166
 
 Keystone 23% $409
 $187
 $409
 $176
 
 Nuclear Generating:           
 Peach Bottom 50% $1,328
 $348
 $1,272
 $306
 
 Salem 57% $1,147
 $277
 $1,077
 $304
 
 Nuclear Support Facilities Various
 $239
 $81
 $238
 $71
 
 Pumped Storage Facilities:           
 Yards Creek 50% $44
 $26
 $42
 $25
 
   Merrill Creek Reservoir 14% $1
 $—
 $1
 $—
 
             
As of December 31,
20202019
OwnershipAccumulatedAccumulated
InterestPlantDepreciationPlantDepreciation
 Millions
PSE&G:
Transmission FacilitiesVarious$161 $63 $161 $60 
PSEG Power:
Nuclear Generating:
Peach Bottom50 %$1,405 $455 $1,340 $435 
Salem57 %$1,321 $387 $1,256 $384 
Nuclear Support FacilitiesVarious$226 $97 $247 $107 
Pumped Storage Facilities:
Yards Creek (A)50 %$0 $0 $55 $27 
Merrill Creek Reservoir14 %$1 $0 $1 $0 
(A)In September 2020, PSEG Power completed the sale of its ownership interest in this generation facility. See Note 4. Early Plant Retirements/Asset Dispositions for additional information.
PSEG Power holds undivided ownership interests in the jointly-owned facilities above. PSEG Power is entitled to shares of the generating capability and output of each unit equal to its respective ownership interests. PSEG Power also pays its ownership share of additional construction costs, fuel inventory purchases and operating expenses. PSEG Power’s share of expenses for the jointly-owned facilities is included in the appropriate expense category. Each owner is responsible for any financing with respect to its pro rata share of capital expenditures.
PSEG Power co-owns Salem and Peach Bottom with Exelon Generation. PSEG Power is the operator of Salem and Exelon Generation is the operator of Peach Bottom. A committee appointed by the co-owners provides oversight. Proposed O&M budgets and requests for major capital expenditures are reviewed and approved as part of the normal PSEG Power governance process.
GenOn Northeast Management Company is a co-owner and the operator for Keystone Generating Station and Conemaugh Generating Station. A committee appointed by the co-owners provides oversight. Proposed O&M budgets and requests for major capital expenditures are reviewed and approved as part of the normal Power governance process.
Power is a co-owner in the Yards Creek Pumped Storage Generation Facility. Jersey Central Power & Light Company (JCP&L) is also a co-owner and the operator of this facility. JCP&L submits separate capital and O&M budgets, subject to Power’s approval as part of the normal Power governance process.
PSEG Power is a minority owner in the Merrill Creek Reservoir and Environmental Preserve in Warren County, New Jersey. Merrill Creek Owners Group is the owner-operator of this facility. The operator submits separate capital and O&M budgets, subject to PSEG Power’s approval as part of the normal PSEG Power governance process.
Note 6.7. Regulatory Assets and Liabilities
PSE&G prepares its financial statements in accordance with GAAP for regulated utilities as described in Note 1. Organization, Basis of Presentation and Summary of Significant Accounting Policies. PSE&G has deferred certain costs based on rate orders issued by the BPU or FERC or based on PSE&G’s experience with prior rate cases.proceedings. Most of PSE&G’s Regulatory Assets and Liabilities as of December 31, 20172020 are supported by written orders, either explicitly or implicitly through the BPU’s treatment of various cost items. These costs will be recovered and amortized over various future periods.
Regulatory Assets and other investments and costs incurred under our various infrastructure filings and clause mechanisms are subject to prudence reviews and can be disallowed in the future by regulatory authorities. To the extent that collection of any

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infrastructure or clause mechanism revenue, Regulatory Assets or payments of Regulatory Liabilities is no longer probable, the amounts would be charged or credited to income.
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PSE&G had the following Regulatory Assets and Liabilities:
       
   As of December 31, 
   2017 2016 
   Millions 
 Regulatory Assets     
 Current     
 New Jersey Clean Energy Program $128
 $142
 
 Weather Normalization Clause (WNC) 40
 49
 
 Electric Energy Costs—Basic Generation Service 23
 2
 
 FERC Formula Rate True-up 12
 —
 
 Other 8
 6
 
 Total Current Regulatory Assets $211
 $199
 
 Noncurrent     
 Pension and OPEB Costs $1,488
 $1,403
 
 Manufactured Gas Plant (MGP) Remediation Costs 358
 403
 
 Deferred Income Taxes 282
 507
 
 Storm Damage Deferrals 241
 239
 
 Electric Transmission and Gas Cost of Removal 199
 189
 
 Remediation Adjustment Charge (RAC) (Other SBC) 172
 180
 
 Conditional Asset Retirement Obligation 162
 157
 
 Green Program Recovery Charges (GPRC) 98
 91
 
 Unamortized Loss on Reacquired Debt and Debt Expense 55
 61
 
 Gas Costs—Basic Gas Supply Service (BGSS) 30
 —
 
 FERC Formula Rate True-up 16
 —
 
 Other 121
 89
 
 Total Noncurrent Regulatory Assets $3,222
 $3,319
 
 Total Regulatory Assets $3,433
 $3,518
 
       
 As of December 31,
 20202019
Millions
Regulatory Assets
Current
New Jersey Clean Energy Program$143 $143 
Societal Benefits Charge (SBC)82 30 
Electric Energy Costs—Basic Generation Service (BGS)60 57 
2018 Distribution Base Rate Case Regulatory Assets (BRC)56 56 
Formula Rate True-up23 52 
Other5 13 
Total Current Regulatory Assets369 351 
Noncurrent
Pension and OPEB Costs$1,489 $1,284 
Deferred Income Tax Regulatory Assets1,014 966 
Manufactured Gas Plant (MGP) Remediation Costs320 357 
Electric Transmission and Gas Cost of Removal189 216 
Asset Retirement Obligation184 172 
Green Program Recovery Charges (GPRC)139 118 
Remediation Adjustment Charge (RAC) (Other SBC)134 158 
BRC103 159 
Deferred Storm Costs99 12 
COVID-19 Deferral51 0 
Unamortized Loss on Reacquired Debt and Debt Expense36 42 
Gas Costs—BGSS26 27 
Other88 166 
Total Noncurrent Regulatory Assets3,872 3,677 
Total Regulatory Assets$4,241 $4,028 
As of December 31,
 20202019
Millions
Regulatory Liabilities
Current
Deferred Income Tax Regulatory Liabilities$223 $193 
Gas Costs—BGSS20 0 
ZEC Liability17 10 
Tax Adjustment Credit (TAC)5 12 
Weather Normalization Charge (WNC)2 15 
Other27 4 
Total Current Regulatory Liabilities294 234 
Noncurrent
Deferred Income Tax Regulatory Liabilities$2,670 $2,955 
Electric Distribution Cost of Removal37 47 
Total Noncurrent Regulatory Liabilities2,707 3,002 
Total Regulatory Liabilities$3,001 $3,236 
       
   As of December 31, 
   2017 2016 
   Millions 
 Regulatory Liabilities     
 Current     
 Gas Costs —BGSS $30
 $6
 
 Gas Margin Adjustment Clause 12
 11
 
 GPRC 3
 28
 
 FERC Formula Rate True-up —
 34
 
 Other 2
 9
 
 Total Current Regulatory Liabilities $47
 $88
 
 Noncurrent     
 Excess Deferred Income Tax Regulatory Liability $2,868
 $—
 
 Electric Distribution Cost of Removal 80
 94
 
 Mark-to-Market (MTM) Contracts —
 20
 
 Other —
 4
 
 Total Noncurrent Regulatory Liabilities $2,948
 $118
 
 Total Regulatory Liabilities $2,995
 $206
 
       


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All Regulatory Assets and Liabilities are excluded from PSE&G’s rate base unless otherwise noted. The Regulatory Assets and Liabilities in the table above are defined as follows:
Conditional
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•Asset Retirement Obligation: These costs represent the differences between rate regulatedrate-regulated cost of removal accounting and asset retirement accounting under GAAP. These costs will be recovered in future rates as assets are retired.
•BRC: Represents deferred costs, primarily comprised of storm costs incurred in the cleanup of major storms from 2010 through 2018, which are being amortized over five years pursuant to the 2018 Distribution Base Rate Case Settlement.
Deferred Income Taxes:•COVID-19 Deferral: These amounts represent incremental costs related to COVID-19 as authorized for deferral in an order issued by the portionBPU to all New Jersey regulated utilities in July 2020. The BPU authorized such utilities to create a COVID-19-related Regulatory Asset by deferring on their books and records the prudently incurred incremental costs related to COVID-19 during the Regulatory Asset period, beginning on March 9, 2020 through September 30, 2021, or 60 days after the New Jersey governor determines that the Public Health Emergency is no longer in effect, or in the absence of such a determination, 60 days from the time the Public Health Emergency automatically terminates by law, whichever is later. Deferred costs are to be offset by any federal or state assistance that the utility may receive as a direct result of the COVID-19 pandemic. Utilities must file quarterly reports of the costs incurred and offsets. Each participating utility must file a petition documenting its prudently incurred incremental COVID-19 costs by December 31, 2021, or within 60 days of the close of the Regulatory Asset period as described above, whichever is later. Any potential rate recovery, including any prudency determinations and the appropriate period of recovery, will be addressed through that filing, or in the alternative, the utility may request that the BPU defer consideration of rate recovery for a future base rate case.
•Deferred Income Tax Regulatory Assets: These amounts relate to deferred income taxes arising from utility operations that have not been included in customer rates relating to depreciation, ITCs and other flow-through items, including the flowback to customers of accumulated deferred income taxes related to tax repair deductions. As part of its base rate case settlement with the BPU and the establishment of the TAC mechanism in 2018, PSE&G agreed to a ten-year flowback to customers of its accumulated deferred income taxes from previously realized tax repair deductions which resulted in the recognition of a $581 million Regulatory Asset and Regulatory Liability as of September 30, 2018. In addition, PSE&G agreed to the current flowback of tax benefits from ongoing tax repair deductions as realized which results in the recording of a Regulatory Asset upon flowback. For the years ended December 31, 2020 and 2019, PSE&G had provided $31 million and $58 million, respectively, in current tax repair flowbacks to customers. The recovery and amortization of the tax repair-related Deferred Income Tax Regulatory Assets will be recovered or refunded through future rates, based upon established regulatory practices. In December 2017, new tax legislation was enacted (Tax Act) reducingdetermined in PSE&G’s subsequent base rate cases.
•Deferred Income Tax Regulatory Liabilities: These liabilities relate to amounts due to customers for excess deferred income taxes as a result of the statutory U.S.reduction in the federal corporate income tax rate provided in the Tax Cuts and Jobs Act of 2017 (Tax Act), and accumulated deferred income taxes from a maximumpreviously realized distribution-related tax repair deductions. As part of 35% to 21%, effective January 1, 2018.its settlement with its regulators, PSE&G is subjectagreed to Financial Accounting Standards Board (FASB) Accounting Standards Codification 740, Income Taxes (ASC 740), which requires thatrefund the effect onexcess deferred income taxes as follows:
•Unprotected distribution-related excess deferred income taxes are being refunded to customers over five years through PSE&G’s TAC mechanism as approved in its 2018 distribution base rate proceeding. As of December 31, 2020, the balance remaining to be flowed back to customers was approximately $520 million with the remaining flowback period through 2023.
•Protected distribution-related excess deferred income taxes are being refunded to customers over the remaining useful life of distribution property, plant and equipment through PSE&G’s TAC mechanism. As of December 31, 2020, the balance remaining to be flowed back to customers was approximately $933 million.
•Previously realized distribution-related tax assetsrepair deductions are being refunded to customers over ten years through PSE&G’s TAC mechanism. As of December 31, 2020, the balance remaining to be flowed back to customers was approximately $500 million through 2028.
•Protected transmission-related excess deferred income taxes are being refunded to customers over the remaining useful life of transmission property, plant and liabilitiesequipment through PSE&G’s transmission formula rate mechanism. As of a changeDecember 31, 2020, the balance remaining to be flowed back to customers was approximately $940 million.
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•Unprotected transmission-related deferred income taxes were fully refunded to customers in tax rates be recognized2019 and 2020.
•Deferred Storm Costs: Incremental costs incurred in the period the taxrestoration and related costs from major storms in 2019 and 2020 for which PSE&G will seek recovery in its next base rate was enacted. The impact of reduction in tax rate is the primary reason for the decrease in the Regulatory Asset.
proceeding.
•Electric and Gas Cost of Removal: PSE&G accrues and collects in rates for the cost of removing, dismantling and disposing of its transmission and distributionT&D assets upon retirement. The regulatory assetRegulatory Asset or liabilityLiability for non-legally required cost of removal represents the difference between amounts collected in rates and costs actually incurred.
•Electric Energy Costs—Basic Generation Service: BGS: These costs represent the over or under recovered amounts associated with Basic Generation Services (BGS),BGS, as approved by the BPU. Pursuant to BPU requirements, PSE&G serves as the supplier of last resort for electric customers within its service territory that are not served by another supplier. Pricing for those services are set by the BPU as a pass-through, resulting in no margin for PSE&G’s operations. Over or under recovered balances with interest are returned or recovered through monthly filings.
Excess Deferred Income Tax Regulatory Liability: The $2.9 billion Regulatory Liability represents the future revenue reduction of •Formula Rate True-Up: PSE&G’s existing $2.1 billion Accumulated Deferred Income Tax liabilities thattransmission revenues are in excessearned under a FERC-approved annual formula rate mechanism which provides for an annual filing of what is needed to offset future tax liabilities as a result of the Tax Act that reduces the federal corporate income tax rate from a maximum of 35% to 21%an estimated revenue requirement with rates effective January 1 2018. The excess deferred income taxes are primarily relatedof each year and a true-up to the difference between book and tax plant depreciation and under the new tax legislation cannot be returned to customers any faster than over the remaining regulatory lives of the related property. For the remaining excess deferred taxes, the mechanism and timing of these refunds will be determined by the BPU and FERC.
that estimate based on actual revenue requirements.
FERC Formula Rate True-up: Over or under collection of transmission earnings calculated using a FERC approved formula. Over or under collected balances with interest are returned or recovered through the subsequent annual filing.
•Gas Costs—Basic Gas Supply Service:BGSS: These costs represent the over or under recovered amounts associated with Basic Gas Supply Service (BGSS),BGSS, as approved by the BPU. Pursuant to BPU requirements, PSE&G serves as the supplier of last resort for gas customers within its service territory that are not served by another supplier. Pricing for those services are set by the BPU as a pass-through, resulting in no margin for PSE&G’s operations. Over or under collected balances are returned or recovered through an annual filing. Interest is accrued only on over recovered balances.
Gas Margin Adjustment Clause: This mechanism credits Firm delivery customers for net distribution margin revenue collected from Transportation Gas Service Non-Firm (TSG-NF) delivery customers. The balance represents the difference between the net margin collected from the TSG-NF Customers versus bill credits provided to Firm delivery customers. Over or under recovered balances with interest are returned or recovered through the subsequent annual filing.
•GPRC: This amount represents costs of the over or under collected balances associated with various renewable energy and energy efficiency programs. The CompanyPSE&G files annually with the BPU for recovery of amounts that include a return on and of its investment over the lives of the underlying investments and capital assets which range from 5five to 10ten years. Interest is accrued monthly on any over or under recovered balances. Components of the GPRC include: Carbon Abatement, Energy Efficiency Economic Stimulus Program (EEE), EEE Extension Program, EEE Extension II Program, the Demand Response Program, Solar Generation Investment Program (Solar 4 All)All®), Solar 4 All® Extension, Solar 4 All® Extension II, Solar Loan II Program, Solar Loan III Program, Energy Efficiency (EE) 2017 Program, Clean Energy Future–Energy Efficiency (CEF-EE), and the Transition Renewable Energy Efficiency 2017Certificate (TRECs) Program.
•MGP Remediation Costs: Represents the low end of the range for the remaining environmental investigation and remediation program cleanup costs for manufactured gas plantsMGPs that are probable of recovery in future rates. Once these costs are incurred, they are recovered through the RAC in the SBC over a seven year period with interest.

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MTM Contracts: The estimated fair value of gas hedge contracts and gas cogeneration supply contract. The regulatory asset/liability is offset by a derivative asset/liability and, with respect to the gas hedge contracts only, an intercompany receivable/payable on the Consolidated Balance Sheets.
•New Jersey Clean Energy Program: The BPU approved future funding requirements for Energy Efficiency and Renewable Energy Programs through the first half of 2018.Programs. The BPU funding requirements are recovered through the SBC.
•Pension and OPEB Costs: Pursuant to the adoption of accounting guidance for employers’ defined benefit pension and OPEB plans, PSE&G recorded the unrecognized costs for defined benefit pension and other OPEB plans on the balance sheet as a Regulatory Asset. These costs represent net actuarial gains or losses and prior service costs and transition obligations as a result of adoption, which have not been expensed. These costs are amortized and recovered in future rates.
•RAC (Other SBC): Costs incurred to clean up manufactured gas plantsMGPs which are recovered over seven years with interest through an annual filing.
•SBC: The SBC, as authorized by the BPU and the New Jersey Electric Discount and Energy Competition Act, includes costs related to PSE&G’s electric and gas business as follows: (1) the Universal Service Fund (USF);Fund; (2) Energy Efficiency and Renewable Energy Programs; (3) Electric bad debt expense; and (4) the RAC for incurred MGP remediation expenditures. Over or under recovered balances with interest are to be returned or recovered through an annual filing.
Storm Damage Deferrals: Costs incurred in•TAC: This represents the cleanupover or under collected balances associated with the return of major storms in 2010 through 2017. Asexcess accumulated deferred income taxes and the flowback of December 31, 2017, this includes the $220 million of storm costs, net of insurance recoveries, primarily as a result of Hurricane Irenepreviously realized and Superstorm Sandy, approved for recovery in a future base rate case proceedingcurrent tax repair deductions under a mechanism approved by the BPU order received in September 2014.PSE&G’s 2018 Base Rate Case Settlement. Over or under collected balances are returned or recovered through an annual filing. PSE&G includes a return component on the flowback of the excess accumulated deferred
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income taxes and the previously realized tax repairs. Interest is accrued monthly on any over or under recovered balances.
•Unamortized Loss on Reacquired Debt and Debt Expense: Represents losses on reacquired long-term debt and expenses associated with issuances of new debt, which are recovered through rates over the remaining life of the debt.
•WNC: This represents the over or under recovery of gas margin under the BPU’s weather normalization clause which is filed annually.annually with the BPU. The WNC requires PSE&G to calculate, at the end of each October-to-May period, the level by which margin revenues differed from what would have resulted if normal weather had occurred. Over recoveries are returned to customers in the next winter season while under recoveries (subject to an earnings cap) are recovered from customers in the next winter season.
•ZEC Liability: This represents amounts to be returned to customers for overcollections, including interest associated with the ZEC program whereby PSE&G purchases ZECs from eligible nuclear plants.
Significant 20172019 and 2020 regulatory orders received and currently pending rate filings with FERC and the BPU by PSE&G are as follows:
•BGSS—In September 2020, the BPU provisionally approved PSE&G’s request to maintain the current BGSS rate of 32 cents. This rate is subject to final approval.
Electric and Gas Distribution Base Rate Filing—•CEF-Energy Cloud (EC) or Advanced Metering Infrastructure (AMI) Initiative—In January 2021, the BPU approved PSE&G’s CEF-EC filing to spend approximately $700 million in order to provide its 2.3 million electric customers with smart meters over the next four years. All of the capital and operating costs of the program will be recovered in PSE&G’s next base rate case, expected in the second half of 2024. From the start of the program until the commencement of new base rates, the return on and of the capital portion of the program will be included for recovery in those rates, as well as operating costs and stranded costs associated with the retirement of the existing meters.
•CEF-Electric Vehicles (EV)—In January 2021, the BPU approved a program for PSE&G to provide investments of $166 million for EV charging. All of the capital and operating costs of the program will be recovered in PSE&G’s next base rate case. From the start of the program until the commencement of new base rates, the return on and of the capital portion of the program will be included for recovery in those rates, as well as operating costs.
•CEF-EE, a New Component of the GPRC—In September 2020, the BPU approved PSE&G’s CEF-EE program, authorizing PSE&G to spend $1 billion in program costs. These costs will be recovered through the GPRC, with returns aligned with PSE&G’s most recent base rate case and recovered over a ten-year amortization period.
The approval also included a Conservation Incentive Program, amechanism that will provide for recovery of lost electric and gas variable margin revenues. This mechanism is effective in June 2021 for electric and October 2021 for gas. PSE&G will suspend its gas WNC when the gas deferral period begins.
•COVID-19 Deferral—In July 2020, the BPU authorized regulated utilities in the State of New Jersey to create a COVID-19-related Regulatory Asset by deferring on their books and records the prudently incurred incremental costs related to COVID-19 as described above.
In October 2020, the BPU broadened the scope of the docket to include all pandemic issues in a generic proceeding that will include submission of public comments and consideration of, among other things, the timing and scope of current and planned clean energy programs; other utility filings and mechanisms; utility financial strength; customer concerns; regulatory compliance and priorities; and ensuring the continued provision of safe and adequate service at just and reasonable rates, while recognizing the ramifications from the COVID-19 pandemic.
PSE&G has made three quarterly filings as required by the BPU and recorded a Regulatory Asset of approximately $51 million in 2020 for net incremental costs, including $29 million for incremental bad debt expense associated with customer accounts receivable, which PSE&G believes are recoverable under the BPU order.
•Energy Strong Program II (ES II) Recovery Filing—In December 2020, PSE&G filed its first ES II electric only cost recovery petition seeking BPU approval to recover in electric rates the return on and of ES II electric investments placed in service through January 31, 2021. In February 2021, the petition was updated to reflect actual investments and costs, and requests an annual revenue increase of $13 million with rates effective no earlier than May 1, 2021. This matter is pending.
•Gas System Modernization Program II (GSMP II)—In July and November 2020, the BPU approved PSE&G’s GSMP II cost recovery petition requesting approximately $18 million and $20 million, respectively in gas revenues on
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an annual basis, which included GSMP II investments in service as of February 29, 2020 and August 31,2020, respectively. The increases were effective July 16, 2020 and December 1, 2020.
In December 2020, PSE&G filed its next bi-annual GSMP II cost recovery petition seeking BPU approval to recover in gas base rates an estimated annual revenue increase of approximately $26 million effective June 1, 2021. This increase represents the return on and of GSMP II investments placed in service through February 28, 2021. This request will be updated in March 2021 for actual costs.
•GPRC—In January 2021, the BPU provisionally approved PSE&G’s 2020 GPRC cost recovery petition requesting recovery of approximately $67 million and $20 million in electric and gas revenues, respectively, on an annual basis with rates effective February 1, 2021.
•RAC—In December 2020, PSE&G filed its RAC 28 petition with the BPU seeking recovery of $35 million of net MGP remediation expenditures incurred from August 1, 2019 through July 31, 2020. This matter is pending.
In September 2020, the BPU approved PSE&G’s RAC 27 filing requesting recovery of approximately $53 million in net MGP remediation expenditures incurred from August 1, 2018 through July 31, 2019.
•SBC—In November 2020, PSE&G filed a distribution base rate case as required as a condition of approval ofpetition to increase electric rates by approximately $76 million and decrease its Energy Strong Program approvedgas rates by the BPUapproximately $18 million, on an annual basis, in 2014. The filing requests an approximate one percent increase in revenues and seeksorder to recover investments made to strengthen electric and gas distribution systems. Incosts incurred or expected to be incurred through February 28, 2022 under its filing, PSE&G requested that theseEE and Renewable Energy and Social Programs. The increase to electric rates take into account a reduction inincludes the revenue requirementimpact of increased bad debt expense as a result of the negative economic impact of the ongoing coronavirus pandemic and moratorium on collections. This matter is pending.
•TAC—In October 2020, PSE&G made its annual 2020 TAC filing. The TAC allows for the flowback to customers of excess accumulated deferred income taxes resulting from the reduction of the federal corporate income tax rate reduction from 35% to 21%rates provided in the Tax Act including a one-time credit for estimated excessas well as the accumulated deferred income taxes collected betweenfrom previously realized tax repair deductions and tax benefits from future tax repair deductions as realized. The 2020 TAC filing, updated in January 2021, requests BPU approval to reduce electric revenues by approximately $26 million and increase gas revenues by $48 million on an annual basis starting January 1, 2018 and2021, including an update to the time new rates go into effect, and the flowadditional unprotected amounts to be flowed back to customers of certain additional tax benefits. PSE&G anticipates the new base rates will go into effect in the fourth quarter of 2018.
Separately, in January 2018, the BPU issued an order commencingas a proceeding to ensure that the rate revenue resulting from expenses relating to taxes reflected in rates but no longer owed as the result of the Tax Act shallPrivate Letter Ruling (PLR) discussed below. This matter is pending.
In July 2020, the BPU gave final approval to PSE&G’s 2019TAC filing that had been approved on a provisional basis in January 2020, with additional credits included in the final ruling. The final approval resulted in a reduction to electric and gas revenues of $25 million and $29 million, respectively, on an annual basis, effective July 16, 2020.
PSE&G received a PLR from the Internal Revenue Service (IRS) in April 2020 that concluded thatcertain excess deferred taxes previously classified as protected should be passed ontoclassified as unprotected. Unprotected excess deferred income taxes are not subject to the ratepayers. Thetax normalization rules allowing them to be refunded to customers sooner as agreed to with the BPU. As part of a procedural discovery to obtain the BPU’s final approval, PSE&G proposed that it change its current provisional TAC rates to increase the credit and start flowing back these unprotected amounts starting in July 2020 through December 31, 2024, which the BPU approved. This resulted in a total additional credit to electric and gas customers of $50 million and $46 million, respectively.
•Transition Incentive Program, a New Component of the GPRC—In 2019, the BPU approved an order establishing a Transition Incentive Program to serve as a bridge between the existing Solar Renewable Energy Certificate (SREC) program and a to-be-established successor incentive program and created a new incentive mechanism known as the Transition Renewable Energy Certificate (TRECs) Program. TRECs will be awarded to qualifying solar projects under the new program. In the TREC Order, the BPU directed the New Jersey utilities (including PSE&G)EDCs to make filings by March 2, 2018 setting forth interim ratesengage a TREC Administrator to be effective April 1, 2018 reflecting the new federal corporate tax rate, and to subsequently file proposed final rates, effective July 1, 2018, incorporating all other effectsacquire, on behalf of the Tax Act. This proceedingEDCs, TRECs produced by eligible solar projects, which will be funded through a TREC charge to electric customers collected by the EDCs. The order allows the EDCs to recover their costs associated with the TREC program in an annual filing, subject to approval by the BPU.
In August 2020, the BPU approved PSE&G’s request for increased rates of approximately $23 million annually for recovery of its expected share of TREC costs. These costs will be recovered as a new component of PSE&G’s existing electric GPRC, which is currently pending.updated on an annual basis.
•Transmission Formula Rate Filings—Rates—In June 2017,October 2020, PSE&G filed its 20162020 Annual Transmission Formula Rate Update with FERC which will result in $119 million in increased annual transmission revenue effective January 1, 2021, subject to true-up.
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In June 2020, PSE&G filed its 2019 true-up adjustment pertaining to its transmission formula rates in effect for 2016.2019. This filing resulted in an adjustmentadditional annual revenue requirement of $12$24 million more than the 20162019 originally filed revenues.
revenue.
ForIn April 2020, the IRS issued a PLR to PSE&G concluding that certain excess deferred taxes previously classified as protected should be classified as unprotected. Unprotected excess deferred income taxes are not subject to the normalization rules allowing them to be refunded to customers sooner as agreed to with FERC and the BPU. In July 2020, FERC approved PSE&G’s request to allow the entire amount of these unprotected excess deferred income taxes be returned to customers in the 2019 true-up filing. As a result of the FERC approval, PSE&G recorded a revenue reduction of approximately $38 million in the third quarter of 2020, fully offset by a reduction in Income Tax Expense. The refund will be provided to transmission ratepayers as a reduction to the 2021 transmission rates.
•WNC—In November 2020, the BPU approved PSE&G’s updated WNC resetting the WNC rate to zero to eliminate any recovery of undercollected revenues from the warmer-than-normal 2019-2020 Winter Period. The updated filing eliminated the undercollection due to an earnings test limitation which was updated with actuals for the annual period ended September 2020 as stipulated in the filing. Previously, the BPU had approved a provisional rate effective October 1, 2020 for the collection of $10 million from customers over the 2020-2021 Winter Period. Approximately $2 million in October and November 2020 collections from the provisional rate will be refunded to customers with interest in the next annual filing.
•ZEC Program—In December 2020, the BPU approved PSE&G’s petition to refund a total of $6.2 million, including interest, for overcollections resulting from the ZEC program for the energy years ended May 31, 2020 and 2019. In 2020, PSE&G purchased approximately $154 million in ZECs, including interest, from the eligible nuclear plants selected by the BPU with the final payment made in August 2020. As a result of the collections and required ZEC payments, there was approximately $6 million in overcollected revenues, including interest, for the energy year ended May 31, 2020. This was combined with a $0.2 million overcollection from the prior period for a total of $6.2 million, with the credit to rates effective January 1, 2021.
Note 8. Leases
As of December 31, 2020, PSEG and its subsidiaries were both a lessee and a lessor in operating leases.
Lessee
PSE&G
PSE&G has operating leases for office space for customer service centers, rooftops and land for its Solar 4 All® facilities, equipment, vehicles and land for certain electric substations. These leases have remaining lease terms through 2040, some of which include options to extend the leases for up to 5 five-year terms. Some leases have fixed rent payments that have escalations based on certain indices, such as the CPI. Certain leases contain variable payments.
PSEG Power
PSEG Power has operating leases for buildings, land leases for its solar generating facilities, merchant transmission and equipment. These leases have remaining terms through 2055, some of which include options to extend the leases for up to 7 five-year terms and certain other leases which include options to extend the leases for 15 to 20 year terms. Some leases have fixed rent payments that have escalations based on certain indices, such as the CPI. Certain leases contain variable payments.
Other
Services has operating leases for real estate and office equipment. These leases have remaining terms through 2030. Services’ lease for its headquarters, which ends in 2030, includes options to extend for 2 five-year terms.
Operating Lease Costs
The following amounts relate to total operating lease costs, including both amounts recognized in the Consolidated Statements of Operations during the years ended December 31, 2017, PSE&G recorded an estimated true-up adjustment2020 and 2019 and any amounts capitalized as part of $16 million to its 2017 Annual Formula rate. That true-up will be filed by no later than June 15, 2018.

the cost of another asset, and the cash flows arising from lease transactions.
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In October 2017, the 2018 Annual Formula Rate Update was filed with FERC and requested approximately $212 million in increased annual transmission revenues effective January 1, 2018, subject to true-up. In January 2018, PSE&G filed with FERC a revised 2018 Annual Transmission Formula Rate Update reducing the 2018 transmission annual revenue requirement to reflect the federal corporate income tax rate reduction from 35% to 21%, effective January 1, 2018, provided in the Tax Act. This change in the federal corporate tax rate reduces the annual revenue requirement by $148 million. The revised increase in annual transmission revenues effective January 1, 2018 is $64 million.
Energy Strong Recovery Filing—In March and September of each year, PSE&G files with the BPU for base rate recovery of Energy Strong investments which include a return of and on its investment.
In June 2017, PSE&G submitted the planned update to its March Energy Strong cost recovery petition, originally filed in March 2017, to include Energy Strong investments in service
PSE&GPSEG PowerOtherTotal
Millions
Operating Lease Costs
Year Ended December 31, 2020
  Long-term Lease Costs$26 $14 $14 $54 
  Short-term Lease Costs38 7 0 45 
  Variable Lease Costs2 20 9 31 
Total Operating Lease Costs$66 $41 $23 $130 
Year Ended December 31, 2020
Cash Paid for Amounts Included in the Measurement of Operating Lease Liabilities$17 $14 $14 $45 
Weighted Average Remaining Lease Term in Years12141011
Weighted Average Discount Rate3.5 %4.5 %4.2 %4.0 %
PSE&GPSEG PowerOtherTotal
Millions
Operating Lease Costs
Year Ended December 31, 2019
  Long-term Lease Costs$24 $13 $15 $52 
  Short-term Lease Costs14 10 0 24 
  Variable Lease Costs2 10 10 22 
Total Operating Lease Costs$40 $33 $25 $98 
Year Ended December 31, 2019
Cash Paid for Amounts Included in the Measurement of Operating Lease Liabilities$16 $11 $15 $42 
Weighted Average Remaining Lease Term in Years13141012
Weighted Average Discount Rate3.6 %4.4 %4.2 %4.1 %
Operating lease liabilities as of MayDecember 31, 2017. This filing requested estimated annual increases in electric and gas revenues of $16 million and $2 million, respectively. In August 2017,2020 had the BPU approved these rate increases effective September 1, 2017.
In September 2017, PSE&G filed its Energy Strong electric cost recovery petition seeking BPU approval to recover the revenue requirements associated with Energy Strong capitalized investment costs placed in service from June 1, 2017 through November 30, 2017. The filing was updated in December 2017 requesting an annual increase in electric revenues of $8 million. This matter is pending.
Gas System Modernization Program (GSMP)—In July of each year, PSE&G files with the BPU for base rate recovery of GSMP investments which include a return of and on its investment.
In December 2017, the BPU approved PSE&G’s annual GSMP cost recovery petition, originally filed in July 2017, and updated in October 2017, to include GSMP investments in service as of September 30, 2017. The BPU approved an annual increase in gas revenues of $25 million, effective January 1, 2018.
BGSS—In June 2017, PSE&G made its annual BGSS filing with the BPU requesting an increase in the BGSS rate from approximately 34 cents to 37 cents per therm effective October 1, 2017. In September 2017, the BPU approved a Stipulation in this matter on a provisional basis and the BGSS rate was increased. In December 2017 and February 2018, PSE&G filed with the BPU for self-implementing monthly bill credits of 15 cents per therm for the months of January, February and March 2018. These monthly bill credits are estimated to provide approximately $100 million in customer credits. In November 2017, a filing was made by the Retail Energy Supply Association (RESA) with the BPU requesting that the BPU revisit the BGSS process and establish a gas capacity release program. This filing, which remains pending, is applicable to all New Jersey gas utilities.
Green Program Recovery Charges (GPRC)—Each year PSE&G files with the BPU for annual recovery for the 11 combined components of its electric and gas Green Program investments which include a return on its investment and recovery of expenses.
In March 2017, the BPU gave final approval to PSE&G’s 2016 GPRC cost recovery petition to recover approximately$37 million and $13 million in electric and gas revenues, respectively,following maturities on an annual basis associated with PSE&G’s implementation of these BPU approved GPRC programs for the period October 1, 2016 through September 30, 2017. The rates were effective May 1, 2017. This Order also included the return of approximately $5 million in remaining overcollections from the completed Securitization Transition Charge.undiscounted basis:
In June 2017, PSE&G filed its 2017 GPRC cost recovery petition requesting recovery of approximately $47 million and $13 million in electric and gas revenues, respectively, on an annual basis associated with PSE&G’s implementation of these BPU approved programs for the period October 1, 2017 through September 30, 2018. This proceeding is ongoing.
In August 2017, the BPU approved PSE&G’s petition for an Energy Efficiency 2017 Program (EE 2017) to extend three existing energy efficiency subprograms (multi-family, direct install and hospital efficiency) and establish two new residential energy efficiency offerings. The two new offerings include deployment of smart thermostats and a pilot program to provide residential customers with energy usage information enabling them to reduce consumption. The Order allows PSE&G to extend the subprogram offerings and establish the residential energy efficiency subprograms under its existing energy efficiency clause recovery process. The EE 2017 allows for $69 million of additional investment and $16 million of additional administrative and information technology costs. The EE 2017 was added as the 11th component of the GPRC rate effective September 1, 2017.
PSE&GPSEG PowerOtherTotal
Millions
2021$16 $14 $15 $45 
202213 14 15 42 
202311 8 15 34 
202410 3 15 28 
20258 3 15 26 
Thereafter69 47 75 191 
Total Minimum Lease Payments$127 $89 $150 $366 
Weather Normalization Clause—In April 2017, the BPU gave final approval to PSE&G petition to collect $54 million in net deficiency gas revenues as a result of the warmer than normal 2015-2016 Winter Period.
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In September 2017, the BPU approved onThe following is a provisional basis, PSE&G’s petition to collect $31 million in net deficiency gas revenues as a resultreconciliation of the warmer than normal 2016-2017 Winter Periodundiscounted cash flows to the discounted Operating Lease Liabilities recognized on the Consolidated Balance Sheets:
As of December 31, 2020
PSE&GPSEG PowerOtherTotal
Millions
Undiscounted Cash Flows$127 $89 $150 $366 
Reconciling Amount due to Discount Rate(26)(27)(27)(80)
Total Discounted Operating Lease Liabilities$101 $62 $123 $286 
As of December 31, 2019
PSE&GPSEG PowerOtherTotal
Millions
Undiscounted Cash Flows$126 $100 $168 $394 
Reconciling Amount due to Discount Rate(27)(28)(33)(88)
Total Discounted Operating Lease Liabilities$99 $72 $135 $306 
As of December 31, 2020, the current portions of Operating Lease Liabilities included in Other Current Liabilities were $34 million, $13 million and a$11 million for PSEG, PSE&G and PSEG Power, respectively. As of December 31, 2019, the current portions of Operating Lease Liabilities included in Other Current Liabilities were $33 million, $12 million and $10 million for PSEG, PSE&G and PSEG Power, respectively.
Lessor
PSEG Power
Certain of PSEG Power’s sales agreements related to its solar generating plants qualify as operating leases with remaining carryover balanceterms through 2043 with no extension terms. Lease income is based on solar energy generation; therefore, all rental income is variable under these leases. As of $24 million in net deficiency gas revenues from the 2015-2016 Winter Period forDecember 31, 2020, PSEG Power’s solar generating plants subject to these leases had a total recoverycarrying value of $55 million$376 million.
Other
Energy Holdings is the lessor in net deficiency revenues. leveraged leases. See Note 9. Long-Term Investments and Note 10. Financing Receivables.
Energy Holdings is the lessor in two operating leases for domestic energy generation facilities with remaining terms through 2036, one of which has an optional renewal period. As of December 31, 2020, Energy Holdings’ property subject to these leases had a total carrying value of $83 million.
Energy Holdings was previously the lessor in operating leases for real estate assets which were sold in March 2020.
The deficiency will be collected from customers overfollowing is the 2017-2018operating lease income for PSEG Power and 2018-2019 Winter Periods (October 1 through May 31). Final approval in this matter is pending.Energy Holdings for the years ended December 31, 2020 and 2019:
PSEG PowerEnergy HoldingsTotal
Millions
Operating Lease Income
Year Ended December 31, 2020
Fixed Lease Income$0 $15 $15 
Variable Lease Income26 0 26 
Total Operating Lease Income$26 $15 $41 
Year Ended December 31, 2019
Fixed Lease Income$0 $22 $22 
Variable Lease Income23 0 23 
Total Operating Lease Income$23 $22 $45 
Remediation Adjustment Charge (RAC)—In June 2017,
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Energy Holdings’ operating leases had the BPU approved PSE&G’s filing with respect to its RAC 24 petition allowing recoveryfollowing minimum future fixed lease receipts as of $41 million effective July 10, 2017 related to net Manufactured Gas Plant expenditures from August 1, 2015 through JulyDecember 31, 2016. In February 2018, PSE&G filed a RAC 25 Petition with the BPU requesting recovery of $63 million of net Manufactured Gas Plant expenditures from August 1, 2016 through July 31, 2017. This matter is pending.
2020:
Universal Service Fund (USF)/Lifeline—In September 2017, the BPU approved rates set to recover state-wide costs incurred by New Jersey electric and gas distribution companies under the State’s USF/Lifeline energy assistance programs effective October 1, 2017. PSE&G earns no margin on the collection of the USF and Lifeline programs resulting in no impact on its Consolidated Statement of Operations.
Millions
2021$14 
202214 
202314 
202414 
202514 
Thereafter227 
Total Minimum Future Lease Receipts$297 
Note 7.9. Long-Term Investments
Long-Term Investments as of December 31, 20172020 and 20162019 included the following:
 As of December 31,
 20202019
 Millions
PSE&G
Life Insurance and Supplemental Benefits$100 $111 
Solar Loans122 137 
PSEG Power
Equity Method Investments (A)64 66 
Energy Holdings
Lease Investments250 497 
Equity Method Investments0 1 
Total Long-Term Investments$536 $812 
       
   As of December 31, 
   2017 2016 
   Millions 
 PSE&G     
 Life Insurance and Supplemental Benefits $130
 $140
 
 Solar Loans 150
 159
 
 Power   
 Partnerships and Corporate Joint Ventures (Equity Method Investments) (A) 87
 102
 
 Energy Holdings     
 Lease Investments 565
 649
 
 Total Long-Term Investments $932
 $1,050
 
       
(A)During the three years ended December 31, 2020, 2019 and 2018, dividends from these investments were $15 million, $15 million and $16 million, respectively.
(A)
During the three years ended December 31, 2017, 2016 and 2015, dividends from these investments were $18 million, $18 million and $16 million, respectively.
Leases
Energy Holdings, through several of its indirect subsidiary companies,subsidiaries, has investments in domestic energy and real estate assets subject primarily to leveraged lease accounting. A leveraged lease is typically comprised of an investment by an equity investor and debt provided by a third-party debt investor. The debt is recourse only to the assets subject to lease and is not included on PSEG’s Consolidated Balance Sheets. As an equity investor, Energy Holdings’ equity investments in the leases are comprised of the total expected lease receivables over the lease terms plus the estimated residual values at the end of the lease terms, reduced for any income not yet earned on the leases. This amount is included in Long-Term Investments on PSEG’s Consolidated Balance Sheets. The more rapid depreciation of the leased property for tax purposes creates tax cash flow that will be repaid to the taxing authority in later periods. As such, the liability for such taxes due is recorded in Deferred Income Taxes on PSEG’s Consolidated Balance Sheets.
DuringIn September 2020, wholly owned subsidiaries of PSEG Energy Holdings L.L.C. (the Sellers) completed the thirdsale of their ownership interests in the Powerton and Joliet generation facilities and related assets, including the assumption by the purchaser of related liabilities. The loss, net of taxes, resulting from the transaction was immaterial. In December 2020, the leveraged lease relating to our interest in the Shawville facilities was modified and extended. Accordingly, the Shawville leveraged lease was reclassified as an operating lease and the underlying assets were recorded in Property, Plant and Equipment. See Note 8. Leases.
In the second quarter of 2016,2020, Energy Holdings completed its annual review of estimated residual values embedded in domestic energy leveraged leases and determined no impairments were necessary. During the NRG REMA, LLC (REMA) leveraged leases. Thesecond quarter of 2019, the outcome of Energy Holdings’ annual review indicated that the revisedupdated residual value estimates wereestimate of the coal-fired Powerton lease was lower than the recorded residual valuesvalue and the decline was deemed to be other than temporary due to theas a result of expected future adverse economic conditions experienced by coal generation in PJM, as discussed in Note 3. Early Plant Retirements, negatively impacting the economic outlook of the leased assets.market conditions. As a result, a pre-tax write-down of $137$58 million was reflected in Operating Revenues in the quarter ended September 30, 2016,2019, calculated by comparing the gross investment in the leases before and after the revised residual estimates. During the fourth quarter of 2016, Energy Holdings recorded a $10 million charge for its best estimate of loss as a result of the current liquidity issues facing REMA, which was reflected in Operating Revenues and is included in Gross Investments in Leases as of December 31, 2016. For additional information, see Note 8. Financing Receivables.

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During the first quarter of 2017, due to continuing liquidity issues facing REMA, economic challenges facing coal generation in PJM, and based upon an ongoing review of available alternatives as well as certain recent discussions with REMA management, Energy Holdings recorded an additional $55 million pre-tax charge for its current best estimate of loss related to the lease receivables.
In June 2017, GenOn Energy, Inc. (GenOn) and certain of its subsidiaries filed voluntary petitions for relief under Chapter 11 of the United States Bankruptcy Code. REMA was not included in the GenOn filing. Energy Holdings continues to monitor the restructuring of GenOn and its possible impacts on REMA and continues to discuss the situation with various parties relevant to this matter. During the second quarter of 2017, Energy Holdings completed its review of estimated residual values embedded in its leveraged lease portfolio of generating assets and the outcome indicated that one of the residual value estimates was lower than the recorded residual value due to a further deterioration of market conditions and changes to operating cost estimates. This decline was determined to be other than temporary. As a result, a pre-tax write-down of $7 million was recorded in the quarter ended June 30, 2017. In addition, based on an ongoing review of (i) the liquidity challenges facing REMA and (ii) available alternatives, Energy Holdings recorded an additional $15 million pre-tax charge in the quarter ended June 30, 2017 for its current best estimate of loss related to lease receivables. Pre-tax write-downs and additional charges are reflected in Operating Revenues and are included in Gross Investment in Leases as of December 31, 2017.
In January 2018, certain subsidiaries of Energy Holdings, REMA, certain holders of the pass-through certificates and other parties entered into a Forbearance Agreement (Forbearance) relating to the Conemaugh facility. Pursuant to the Forbearance, the parties thereto agreed to temporarily forbear from exercising rights and remedies related to certain events of default related to REMA’s obligation to procure additional qualifying credit support. The Forbearance will remain effective until the earlier of (i) the later of (a) April 15, 2018 and (b) two weeks following the date on which Energy Holdings subsidiaries, REMA and/or the consenting certificate holders provide written notice to REMA of its intention to terminate the Forbearance, and (ii) the date on which any event of termination as specified in the Forbearance occurs.
PSEG cannot predict the outcome of GenOn’s restructuring process or the possible related impact on REMA. PSEG continues to monitor any changes to REMA’s and GenOn’s status and potential impacts on Energy Holdings’ lease investments. If lease rejections or foreclosures were to occur, Energy Holdings could potentially record additional pre-tax write-offs up to its gross investment in these facilities and may also be required to accelerate and pay material deferred tax liabilities to the Internal Revenue Service (IRS).
The following table shows Energy Holdings’ gross and net lease investment as of December 31, 20172020 and 2016.2019.
       
   As of December 31, 
   2017 2016 
   Millions 
 Lease Receivables (net of Non-Recourse Debt) $546
 $629
 
 Estimated Residual Value of Leased Assets 326
 346
 
 Total Investment in Rental Receivables 872
 975
 
 Unearned and Deferred Income (307) (326) 
 Gross Investments in Leases 565
 649
 
 Deferred Tax Liabilities (480) (674) 
 Net Investments in Leases $85
 $(25) 
       
In December 2017, new tax legislation was enacted, reducing the statutory U.S. corporate income tax rate from a maximum of 35% to 21%, effective January 1, 2018. PSEG is subject to ASC 740, which requires that the effect on deferred tax assets and liabilities of a change in tax rates be recognized in the period the tax rate was enacted. The impact of the reduced tax rate is the primary reason for the decrease in Deferred Tax Liabilities. For additional information, see Note 20. Income Taxes.



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 As of December 31,
 20202019
 Millions
Lease Receivables (net of Non-Recourse Debt)$299 $498 
Estimated Residual Value of Leased Assets55 202 
Total Investment in Rental Receivables354 700 
Unearned and Deferred Income(104)(203)
Gross Investments in Leases250 497 
Deferred Tax Liabilities(64)(328)
Net Investments in Leases$186 $169 
The pre-tax income (loss) and income tax effects related to investments in leases, excluding gains and losses on sales and the impacts of the Tax Act, were as follows:
         
   Years Ended December 31, 
   2017 2016 2015 
   Millions 
 Pre-Tax Income (Loss) from Leases $(69) $(135) $12
 
 Income Tax Expense (Benefit) on Income from Leases $(26) $(51) $5
 
         
 Years Ended December 31,
 202020192018
 Millions
Pre-Tax Income (Loss) from Leases$18 $(39)$17 
Income Tax Expense (Benefit) on Income (Loss) from Leases$2 $(22)$6 
Equity Method InvestmentsInvestment
PSEG Power had the following equity method investmentsa 50% ownership interest in Kalaeloa, a combined-cycle generation facility in Hawaii of $64 million and $66 million as of December 31, 20172020 and 2016:2019, respectively.
        
  As of December 31,     
 Name2017 2016 Location % Owned 
  Millions     
 Power        
 Keystone Fuels, LLC$8
 $7
 PA 23% 
 Conemaugh Fuels, LLC8
 8
 PA 23% 
 PennEast Pipeline—
 11
 PA 10% 
 Kalaeloa71
 76
 HI 50% 
 Total$87
 $102
     
          
Note 8.10. Financing Receivables
PSE&G
PSE&G sponsors a solar loan program&G’s Solar Loan Programs are designed to help finance the installation of solar power systems throughout its electric service area. Interest income on the loans is recorded on an accrual basis. The loans are generally paid back with solar renewable energy certificates (SRECs)SRECs generated from the related installed solar electric system. InPSE&G uses collection experience as a credit quality indicator for its Solar Loan Programs and conducts a comprehensive credit review for all prospective borrowers. As of December 31, 2020, none of the solar loans were impaired; however, in the event of a loan default or if a loan becomes impaired, the basis of the solar loan would be recovered through a regulatory recovery mechanism. NoneAs of December 31, 2020, none of the solar loans were delinquent and no loans are impaired; however,currently expected to become delinquent in the event a loan becomes impaired, the basislight of the loan would be recovered through a regulatory recoverypayment mechanism.
Therefore, no current credit losses have been recorded for Solar Loan Programs I, II and III. A substantial portion of these amounts are noncurrent and reported in Long-Term Investments on PSEG’s and PSE&G’s Consolidated Balance Sheets. The following table reflects the outstanding loans including the noncurrent portion reported in Note 7. Long-Term Investments, by class of customer, none of which would be considered “non-performing.”
 As of December 31,
Outstanding Loans by Class of Customer20202019
 Millions
Commercial/Industrial$145 $156 
Residential6 8 
Total151 164 
Current Portion (included in Accounts Receivable)(29)(28)
Noncurrent Portion (included in Long-Term Investments)$122 $136 
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 Outstanding Loans by Class of Customer 
   As of December 31, 
 Consumer Loans 2017 2016 
   Millions 
 Commercial/Industrial $158
 $164
 
 Residential 10
 11
 
 Total $168
 $175
 
       
The solar loans originated under three Solar Loan Programs are comprised as follows:

ProgramsBalance as of December 31, 2020Funding ProvidedResidential Loan TermNon-Residential Loan Term
Millions
Solar Loan I$20 prior to 201310 years15 years
Solar Loan II69 prior to 201510 years15 years
Solar Loan III62 largely funded as of December 31, 202010 years10 years
Total$151 
The average life of loans paid in full is eight years, which is lower than the loan terms of 10 to 15 years due to the generation of SRECs being greater than expected and/or cash payments made to the loan. Payments on all outstanding loans were current as of December 31, 2020 and have an average remaining life of approximately four years.
Energy Holdings
Energy Holdings had a net investmentinvestments in domestic energy and real estate assets subject to leveraged lease accounting of $85$186 million as of December 31, 20172020 and $(25)$169 million as of December 31, 20162019 (See Note 7.9. Long-Term Investments).

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The corresponding receivables associated with the lease portfolio are reflected as follows, net of non-recourse debt. The ratings in the table represent the ratings of the entities providing payment assurance to Energy Holdings.
Lease Receivables, Net of
Non-Recourse Debt
Counterparties’ Credit Rating Standard & Poor’s (S&P) as of December 31, 2020As of December 31, 2020
Millions
AA$9 
A-54 
BBB+ to BBB196 
BB+40 
Total$299
     
 
  
 
Lease Receivables, Net of
Non-Recourse Debt
 
 Counterparties’ Credit Rating Standard & Poor’s (S&P) as of December 31, 2017 As of December 31, 2017 
   Millions 
 AA $15
 
 BBB+, BBB, BBB- 316
 
 BB- 133
 
 CCC- 82
 
 Total $546
 
     
The “BB-“BB+” and the “CCC-” ratingsrating in the preceding table representrepresents a lease receivablesreceivable related to coalthe Merrill Creek Reservoir. Metropolitan Edison Company (a subsidiary of First Energy) is the lease counterparty and gas-fired assets in Illinois and Pennsylvania, respectively.fully guarantees the lease payments. As of December 31, 2017,2020, the gross investment in the leases of such assets, net of non-recourse debt,this lease was $335$26 million, ($(67)20 million, net of deferred taxes). A more detailed description of such assets under lease is presented
0PSEG recorded no credit losses in 2020 for the following table.
                 
 Asset Location 
Gross
Investment
 
 %
Owned
 Total MW 
Fuel
Type
 
Counterparties’
S&P Credit
Ratings
 Counterparty 
     Millions           
 Powerton Station Units 5 and 6 IL $132
 64% 1,538
 Coal BB- NRG Energy, Inc. 
 Joliet Station Units 7 and 8 IL $85
 64% 1,036
 Gas BB- NRG Energy, Inc. 
 Keystone Station Units 1 and 2 PA $20
 17% 1,711
 Coal CCC- REMA (A) 
 Conemaugh Station Units 1 and 2 PA $20
 17% 1,711
 Coal CCC- REMA (A) 
 Shawville Station Units 1, 2, 3 and 4 PA $78
 100% 596
 Gas CCC- REMA (A) 
                 
(A)GenOn Energy Inc. (GenOn), and certain of its subsidiaries (which did not include REMA) filed voluntary petitions for relief under Chapter 11 of the U.S. Bankruptcy Code. GenOn is currently engaged in a balance sheet restructuring, which will take an undetermined time to complete. Certain subsidiaries of Energy Holdings, REMA, consenting holders of the pass-through certificates and other parties entered into a Forbearance relating to the Conemaugh facility. For additional information, see Note 7. Long-Term Investments.
The credit exposure for lessors is partially mitigated through various credit enhancement mechanisms within the lease structures. These credit enhancement features vary from lease to lease.leveraged leases existing on December 31, 2020. Upon the occurrence of certain defaults, indirect subsidiary companiessubsidiaries of Energy Holdings would exercise their rights and seek recovery of their investment, potentially including stepping into the lease directly to protect their investments. While these actions could ultimately protect or mitigate the loss of value, they could require the use of significant capital and trigger certain material tax obligations which could, for certain leases, wholly or partially be mitigated by tax indemnification claims against the counterparty. A bankruptcy of a lessee would likely delay and potentially limit any efforts on the part of the lessors to assert their rights upon default and could delay the monetization of claims. Failure to recover adequate value could ultimately lead to a foreclosure on the assets under lease by the lenders.
Additional factors that may impact future lease cash flows include, but are not limited to, new environmental legislation and regulation regarding air quality, water and other discharges in the process of generating electricity, market prices for fuel, electricity and capacity, overall financial condition of lease counterparties and their affiliates and the quality and condition of assets under lease.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 9. Available-for-Sale Securities11. Trust Investments
NDT Fund
In accordance with NRC regulations, entities owning an interest in nuclear generating facilities are required to determine the costs and funding methods necessary to decommission such facilities upon termination of operation. As a general practice, each nuclear owner places funds in independent external trust accounts it maintains to provide for decommissioning. PSEG Power is required to file periodic reports with the NRC demonstrating that its NDT Fund meets the formula-based minimum NRC funding requirements.
PSEG Power maintains an external master NDT to fund its share of decommissioning costs for its five nuclear facilities upon their respective termination of operation. The trust contains two separate funds: a qualified fund and a non-qualified fund. Section 468A of the Internal Revenue Code limits the amount of money that can be contributed into a qualified fund. PSEG Power’s share of decommissioning costs related to its five nuclear units was estimated to be between $2.8$2.8 billion and $3.0$3.0 billion,, including contingencies. The liability for decommissioning recorded on a discounted basis as of
119

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December 31, 20172020 was approximately $756$852 million and is included in the Asset Retirement Obligation. The funds are managed by third-party investment managers who operate under investment guidelines developed by PSEG Power.
Power classifies investments in the NDT Fund as available-for-sale. The following tables show the fair values and gross unrealized gains and losses for the securities held in the NDT Fund.
           
   As of December 31, 2017 
   Cost 
Gross
Unrealized
Gains
 
Gross
Unrealized
Losses
 
Fair
Value
 
   Millions 
 Equity Securities         
 Domestic $405
 $245
 $(2) $648
 
 International 311
 99
 (3) 407
 
 Total Equity Securities 716
 344
 (5) 1,055
 
 Debt Securities         
 Government 586
 2
 (4) 584
 
 Corporate 400
 4
 (2) 402
 
 Total Debt Securities 986
 6
 (6) 986
 
 Other Securities 92
 —
 —
 92
 
 Total NDT Available-for-Sale Securities $1,794
 $350
 $(11) $2,133
 
         

 
 As of December 31, 2020
 CostGross
Unrealized
Gains		Gross
Unrealized
Losses		Fair
Value
 Millions
Equity Securities
Domestic$519 $305 $(3)$821 
International388 152 (9)531 
Total Equity Securities907 457 (12)1,352 
Available-for-Sale Debt Securities
Government555 27 (1)581 
Corporate528 39 (1)566 
Total Available-for-Sale Debt Securities1,083 66 (2)1,147 
Total NDT Fund Investments (A)$1,990 $523 $(14)$2,499 
    (A)    The NDT Fund Investments table excludes foreign currency of $2 millionas of December 31, 2020,
           
   As of December 31, 2016 
   Cost 
Gross
Unrealized
Gains
 
Gross
Unrealized
Losses
 
Fair
Value
 
   Millions 
 Equity Securities         
 Domestic $439
 $214
 $(3) $650
 
 International 266
 49
—
(8) 307
 
 Total Equity Securities 705
 263
 (11) 957
 
 Debt Securities         
 Government 518
 8
 (6) 520
 
 Corporate 337
 4
 (4) 337
 
 Total Debt Securities 855
 12
 (10) 857
 
 Other Securities 44
 —
 —
 44
 
 Total NDT Available-for-Sale Securities (A) $1,604
 $275
 $(21) $1,858
 
           
(A)The NDT available-for-sale securities table excludes cash of $1 million as of December 31, 2016,        which is part of the NDT Fund.

 As of December 31, 2019
 CostGross
Unrealized
Gains		Gross
Unrealized
Losses		Fair
Value
Millions
Equity Securities
Domestic$425 $238 $(4)$659 
International400 103 (11)492 
Total Equity Securities825 341 (15)1,151 
Available-for-Sale Debt Securities
Government563 16 (2)577 
Corporate470 17 (1)486 
Total Available-for-Sale Debt Securities1,033 33 (3)1,063 
Total NDT Fund Investments (A)$1,858 $374 $(18)$2,214 
115
Table(A)    The NDT Fund Investments table excludes foreign currency of Contents$2 millionas of December 31, 2019, which is part of the NDT Fund.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Net unrealized gains on debt securities of $37 million (after-tax) were included in Accumulated Other Comprehensive Loss on PSEG’s and PSEG Power’s Consolidated Balance Sheets as of December 31, 2020. An impairment of debt securities of $(3) million was included in Net Gains (Losses) on Trust Investments in PSEG Power’s Consolidated Statement of Operations for the year ended December 31, 2020. The costportion of thesenet unrealized gains recognized during 2020 related to equity securities still held at the end of December 31, 2020 was determined on the basis of specific identification.$184 million.
The amounts in the preceding tables do not include receivables and payables for NDT Fund transactions which have not settled at the end of each period. Such amounts are included in Accounts Receivable and Accounts Payable on the Consolidated Balance Sheets as shown in the following table.
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   As of December 31, 2017 As of December 31, 2016 
   Millions 
 Accounts Receivable $24
 $8
 
 Accounts Payable $74
 $5
 
       
As of December 31,
20202019
 Millions
Accounts Receivable$11 $11 
Accounts Payable$12 $11 
The following table shows the value of securities in the NDT Fund that have been in a continuousan unrealized loss position for less than 12 months and greater than 12 months.
 As of December 31, 2020As of December 31, 2019
 Less Than 12
Months		Greater Than 12
Months		Less Than 12
Months		Greater Than 12
Months
 Fair
Value		Gross
Unrealized
Losses		Fair
Value		Gross
Unrealized
Losses		Fair
Value		Gross
Unrealized
Losses		Fair
Value		Gross
Unrealized
Losses
Millions
Equity Securities (A)
Domestic$23 $(2)$6 $(1)$21 $(1)$6 $(3)
International26 (2)27 (7)28 (2)34 (9)
Total Equity Securities49 (4)33 (8)49 (3)40 (12)
Available-for-Sale Debt Securities
Government (B)72 (1)0 0 99 (2)30 0 
Corporate (C)31 (1)7 0 49 0 12 (1)
Total Available-for-Sale Debt Securities103 (2)7 0 148 (2)42 (1)
NDT Trust Investments$152 $(6)$40 $(8)$197 $(5)$82 $(13)
                   
   As of December 31, 2017 As of December 31, 2016 
   
Less Than 12
Months
 
Greater Than 12
Months
 
Less Than 12
Months
 
Greater Than 12
Months
 
   
Fair
Value
 
Gross
Unrealized
Losses
 
Fair
Value
 
Gross
Unrealized
Losses
 
Fair
Value
 
Gross
Unrealized
Losses
 
Fair
Value
 
Gross
Unrealized
Losses
 
   Millions 
 Equity Securities (A)                 
 Domestic $40
 $(2) $—
 $—
 $51
 $(3) $2
 $—
 
 International 29
 (3) 2
 —
 69
 (7) 6
 (1) 
 Total Equity Securities 69
 (5) 2
 —
 120
 (10) 8
 (1) 
 Debt Securities                 
 Government (B) 343
 (2) 91
 (2) 276
 (6) 4
 —
 
 Corporate (C) 191
 (1) 27
 (1) 139
 (3) 15
 (1) 
 Total Debt Securities 534
 (3) 118
 (3) 415
 (9) 19
 (1) 
 NDT Available-for-Sale Securities $603
 $(8) $120
 $(3) $535
 $(19) $27
 $(2) 
                   
(A)Equity Securities—Investments in marketable equity securities within the NDT Fund are primarily in common stocks within a broad range of industries and sectors. Unrealized gains and losses on these securities are recorded in Net Income.
(A)Equity Securities—Investments in marketable equity securities within the NDT Fund are primarily in common stocks within a broad range of industries and sectors. The unrealized losses are distributed over a broad range of securities with limited impairment durations. Power does not consider these securities to be other-than-temporarily impaired as of December 31, 2017.
(B)Debt Securities (Government)—Unrealized losses on Power’s NDT investments in U.S. Treasury obligations and Federal Agency mortgage-backed securities were caused by interest rate changes. These investments are guaranteed by the U.S. government or an agency of the U.S. government. Power also has investments in municipal bonds that are primarily in investment grade securities. It is not expected that these securities will settle for less than their amortized cost. Since Power does not intend to sell these securities before recovery nor will it be more-likely-than-not required to sell, Power does not consider these debt securities to be other-than-temporarily impaired as of December 31, 2017.
(C)Debt Securities (Corporate)—Power’s investments in corporate bonds are primarily in investment grade securities. It is not expected that these securities would settle for less than their amortized cost. Since Power does not intend to sell these securities before recovery nor will it be more-likely-than-not required to sell, Power does not consider these debt securities to be other-than-temporarily impaired as of December 31, 2017.

(B)Debt Securities (Government)—Unrealized gains and losses on these securities are recorded in Accumulated Other Comprehensive Income (Loss). The unrealized losses on PSEG Power’s NDT investments in U.S. Treasury obligations and Federal Agency mortgage-backed securities were caused by interest rate changes. PSEG Power also has investments in municipal bonds. It is not expected that these securities will settle for less than their amortized cost. PSEG Power does not intend to sell these securities nor will it be more-likely-than-not required to sell before recovery of their amortized cost. PSEG Power did not recognize credit losses for U.S. Treasury obligations and Federal Agency mortgage-backed securities because these investments are guaranteed by the U.S. government or an agency of the U.S. government. PSEG Power did not recognize credit losses for municipal bonds because they are primarily investment grade securities.
(C)Debt Securities (Corporate)—Unrealized gains and losses on these securities are recorded in Accumulated Other Comprehensive Income (Loss). Unrealized losses were due to market declines. It is not expected that these securities would settle for less than their amortized cost. PSEG Power does not intend to sell these securities nor will it be more-likely-than-not required to sell before recovery of their amortized cost. PSEG Power did not recognize credit losses for these corporate bonds because they are primarily investment grade securities.
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The proceeds from the sales of and the net realized gains (losses) on securities in the NDT Fund were:
 Years Ended December 31,
 202020192018
 Millions
Proceeds from Sales (A)$2,031 $1,614 $1,398 
Net Realized Gains (Losses):
Gross Realized Gains$214 $107 $121 
Gross Realized Losses(94)(53)(51)
Net Realized Gains (Losses) on NDT Fund (B)120 54 70 
Unrealized Gains (Losses) on Equity Securities in NDT Fund120 196 (209)
Impairment of Available-for-Sale Debt Securities (C)(3)0 0 
Net Gains (Losses) on NDT Fund Investments$237 $250 $(139)
         
   Years Ended December 31, 
   2017 2016 2015 
   Millions 
 Proceeds from Sales (A) $2,137
 $711
 $1,397
 
 Net Realized Gains (Losses):       
 Gross Realized Gains $157
 $53
 $97
 
 Gross Realized Losses (23) (32) (37) 
 Net Realized Gains (Losses) on NDT Fund (B) $134
 $21
 $60
 
         
(A)(A)Includes activity in accounts related to the liquidation of funds being transitioned to new managers.
(B)The cost of these securities was determined on the basis of specific identification.
Gross realized gains and gross realized losses disclosed in accounts related to the preceding table wereliquidation of funds being transitioned to new managers.
(B)The cost of these securities was determined on the basis of specific identification.
(C)PSEG Power recognized in Other Income and Other Deductions, respectively, in PSEG’s andan impairment of available-for-sale debt securities that it intends to sell. PSEG Power’s Consolidated Statements of Operations. Net unrealized gains of $175 million (after-tax)policy is to sell all such securities that are included in Accumulated Other Comprehensive Loss on PSEG’s and Power’s Consolidated Balance Sheets as of December 31, 2017. Under new guidance, equity investments (other than those accounted for using the equity method) will be measured at fair value through Net Income instead of Other Comprehensive Income (Loss), effective January 1, 2018. For additional information, see Note 2. Recent Accounting Standards.rated below investment grade.
The available-for-saleNDT Fund debt securities held as of December 31, 20172020 had the following maturities:
Time FrameFair Value
Millions
Less than one year$20 
1 - 5 years301 
6 - 10 years202 
11 - 15 years81 
16 - 20 years79 
Over 20 years464 
Total NDT Available-for-Sale Debt Securities$1,147
     
 Time Frame Fair Value 
   Millions 
 Less than one year $42
 
 1 - 5 years 320
 
 6 - 10 years 207
 
 11 - 15 years 40
 
 16 - 20 years 65
 
 Over 20 years 312
 
 Total NDT Available-for-Sale Debt Securities $986
 
     
PSEG Power periodically assesses individual debt securities whose fair value is less than amortized cost to determine whether the investments are considered to be other-than-temporarily impaired. For equity securities, management considers the ability and intent to hold for a reasonable time to permit recovery in addition to the severity and duration of the loss. For fixed incomethese securities, management considers its intent to sell or requirement to sell a security prior to expected recovery. In those cases where a sale is expected, any impairment would be recorded through earnings. For fixed income securities where there is no intent to sell or likely requirement to sell, management evaluates whether credit loss is a component of the impairment. If so, that portion is recorded through earnings while the noncredit loss component is recorded through Accumulated Other Comprehensive Income (Loss). In 2017, other-than-temporary impairments of $12 million were recognized on securities in the NDT Fund. Any subsequent recoveries inof the valuenoncredit loss component of these securitiesthe impairment would be recognized inrecorded through Accumulated Other Comprehensive Income (Loss) unless. Any subsequent recoveries of the securities are sold, in which case, any gaincredit loss component would be recognized in income.through earnings. The assessment of fair market value compared to cost is applied on a weighted average basis taking into account various purchase dates and initial cost of the securities.
Rabbi Trust
PSEG maintains certain unfunded nonqualified benefit plans to provide supplemental retirement and deferred compensation benefits to certain key employees. Certain assets related to these plans have been set aside in a grantor trust commonly known as a “Rabbi Trust.”
PSEG classifies investments in the Rabbi Trust as available-for-sale.
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The following tables show the fair values, gross unrealized gains and losses and amortized cost basesbasis for the securities held in the Rabbi Trust.

 As of December 31, 2020
 CostGross
Unrealized
Gains		Gross
Unrealized
Losses		Fair
Value
 Millions
Equity Securities
Domestic$21 $10 $0 $31 
International0 0 0 0 
Total Equity Securities21 10 0 31 
Available-for-Sale Debt Securities
  Government94 6 0 100 
  Corporate123 12 0 135 
Total Available-for-Sale Debt Securities217 18 0 235 
Total Rabbi Trust Investments$238 $28 $0 $266 
 As of December 31, 2019
 CostGross
Unrealized
Gains		Gross
Unrealized
Losses		Fair
Value
Millions
Equity Securities
Domestic$21 $7 $0 $28 
International0 0 0 0 
Total Equity Securities21 7 0 28 
Available-for-Sale Debt Securities
  Government100 4 0 104 
  Corporate107 7 0 114 
Total Available-for-Sale Debt Securities207 11 0 218 
Total Rabbi Trust Investments$228 $18 $0 $246 
117
TableNet unrealized gains on debt securities of Contents
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

           
   As of December 31, 2017 
   Cost 
Gross
Unrealized
Gains
 
Gross
Unrealized
Losses
 
Fair
Value
 
   Millions 
 Equity Securities         
 Domestic $22
 $3
 $—
 $25
 
 International —
 —
 —
 —
 
 Total Equity Securities $22
 $3
 $—
 $25
 
 Debt Securities         
   Government 85
 1
 (1) 85
 
   Corporate 118
 2
 (1) 119
 
 Total Debt Securities 203
 3
 (2) 204
 
 Other Securities 2
 —
 —
 2
 
 Total Rabbi Trust Available-for-Sale Securities $227
 $6
 $(2) $231
 
           
           
   As of December 31, 2016 
   Cost 
Gross
Unrealized
Gains
 
Gross
Unrealized
Losses
 
Fair
Value
 
   Millions 
 Equity Securities         
 Domestic $11
 $11
 $—
 $22
 
 International —
 —
 —
 —
 
 Total Equity Securities 11
 11
 —
 22
 
 Debt Securities         
   Government 105
 —
 (2) 103
 
   Corporate 92
 1
 (2) 91
 
 Total Debt Securities 197
 1
 (4) 194
 
 Other Securities 1
 —
 —
 1
 
 Total Rabbi Trust Available-for-Sale Securities $209
 $12
 $(4) $217
 
           
$13 million (after-tax) were included in Accumulated Other Comprehensive Loss on PSEG’s Consolidated Balance Sheet as of December 31, 2020. The portion of net unrealized gains recognized during 2020 related to equity securities still held at the end of December 31, 2020 was $4 million.
The amounts in the preceding tables do not include receivables and payables for Rabbi Trust Fund transactions which have not settled at the end of each period. Such amounts are included in Accounts Receivable and Accounts Payable on the Consolidated Balance Sheets as shown in the following table.
       
   As of December 31, 2017 As of December 31, 2016 
   Millions 
 Accounts Receivable $2
 $5
 
 Accounts Payable $1
 $3
 
       

As of December 31,
20202019
 Millions
Accounts Receivable$1 $2 
Accounts Payable$1 $0 
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The following table shows the value of securities in the Rabbi Trust Fund that have been in a continuousan unrealized loss position for less than 12 months and greater than 12 months:
 As of December 31, 2020As of December 31, 2019
 Less Than 12
Months		Greater Than 12
Months		Less Than 12
Months		Greater Than 12
Months
 Fair
Value		Gross
Unrealized
Losses		Fair
Value		Gross
Unrealized
Losses		Fair
Value		Gross
Unrealized
Losses		Fair
Value		Gross
Unrealized
Losses
Millions
Available-for-Sale Debt Securities
Government (A)$19 $0 $0 $0 $26 $0 $3 $0 
Corporate (B)2 0 1 0 11 0 2 0 
Total Available-for-Sale Debt Securities21 0 1 0 37 0 5 0 
Rabbi Trust Investments$21 $0 $1 $0 $37 $0 $5 $0 
                   
   As of December 31, 2017 As of December 31, 2016 
   
Less Than 12
Months
 
Greater Than 12
Months
 
Less Than 12
Months
 
Greater Than 12
Months
 
   
Fair
Value
 
Gross
Unrealized
Losses
 
Fair
Value
 
Gross
Unrealized
Losses
 
Fair
Value
 
Gross
Unrealized
Losses
 
Fair
Value
 
Gross
Unrealized
Losses
 
   Millions 
 Equity Securities (A)                 
 Domestic $—
 $—
 $—
 $—
 $—
 $—
 $—
 $—
 
 International —
 —
 —
 —
 —
 —
 —
 —
 
 Total Equity Securities —
 —
 —
 —
 —
 —
 —
 —
 
 Debt Securities                 
 Government (B) 28
 —
 25
 (1) 60
 (2) 1
 —
 
 Corporate (C) 39
 (1) 9
 —
 46
 (2) 3
 —
 
 Total Debt Securities 67
 (1) 34
 (1) 106
 (4) 4
 —
 
 Rabbi Trust Available-for-Sale Securities $67
 $(1) $34
 $(1) $106
 $(4) $4
 $—
 
                   
(A)Debt Securities (Government)—Unrealized gains and losses on these securities are recorded in Accumulated Other Comprehensive Income (Loss). The unrealized losses on PSEG’s Rabbi Trust investments in U.S. Treasury obligations and Federal Agency mortgage-backed securities were caused by interest rate changes. PSEG also has investments in municipal bonds. It is not expected that these securities will settle for less than their amortized cost. PSEG does not intend to sell these securities nor will it be more-likely-than-not required to sell before recovery of their amortized cost. PSEG did not recognize credit losses for U.S. Treasury obligations and Federal Agency mortgage-backed securities because these investments are guaranteed by the U.S. government or an agency of the U.S. government. PSEG did not recognize credit losses for municipal bonds because they are primarily investment grade securities.
(A)Equity Securities—Investments in marketable equity securities within the Rabbi Trust Fund are through a mutual fund which invests primarily in common stocks within a broad range of industries and sectors.
(B)Debt Securities (Government)—Unrealized losses on PSEG’s Rabbi Trust investments in U.S. Treasury obligations and Federal Agency mortgage-backed securities were caused by interest rate changes. These investments are guaranteed by the U.S. government or an agency of the U.S. government. PSEG also has investments in municipal bonds that are primarily in investment grade securities. It is not expected that these securities will settle for less than their amortized cost. Since PSEG does not intend to sell these securities before recovery nor will it be more-likely-than-not required to sell, PSEG does not consider these debt securities to be other-than-temporarily impaired as of December 31, 2017.
(C)Debt Securities (Corporate)—PSEG’s investments in corporate bonds are primarily in investment grade securities. It is not expected that these securities would settle for less than their amortized cost. Since PSEG does not intend to sell these securities before recovery nor will it be more-likely-than-not required to sell, PSEG does not consider these debt securities to be other-than-temporarily impaired as of December 31, 2017.
(B)Debt Securities (Corporate)—Unrealized gains and losses on these securities are recorded in Accumulated Other Comprehensive Income (Loss). Unrealized losses were due to market declines. It is not expected that these securities would settle for less than their amortized cost. PSEG does not intend to sell these securities nor will it be more-likely-than-not required to sell before recovery of their amortized cost. PSEG did not recognize credit losses for these corporate bonds because they are primarily investment grade.
The proceeds from the sales of and the net realized gains (losses) on securities in the Rabbi Trust Fund were:
 Years Ended December 31,
 202020192018
 Millions
Proceeds from Rabbi Trust Sales (A)$203 $173 $103 
Net Realized Gains (Losses):
Gross Realized Gains$19 $7 $2 
Gross Realized Losses(6)(3)(4)
Net Realized Gains (Losses) on Rabbi Trust (B)13 4 (2)
Unrealized Gains (Losses) on Equity Securities in Rabbi Trust3 6 (2)
Net Gains (Losses) on Rabbi Trust Investments$16 $10 $(4)
         
   Years Ended December 31, 
   2017 2016 2015 
   Millions 
 Proceeds from Rabbi Trust Sales (A) $182
 $113
 $104
 
 Net Realized Gains (Losses):       
 Gross Realized Gains $17
 $6
 $3
 
 Gross Realized Losses (5) (5) (2) 
 Net Realized Gains (Losses) on Rabbi Trust (B) $12
 $1
 $1
 
         
(A)Includes activity in accounts related to the liquidation of funds being transitioned to new managers.
(A)Includes activity in accounts related to the liquidation of funds being transitioned to new managers.
(B)The cost of these securities was determined on the basis of specific identification.

(B)The cost of these securities was determined on the basis of specific identification.
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Gross realized gains and gross realized losses disclosed in the above table were recognized in Other Income and Other Deductions, respectively, in the Consolidated Statements of Operations. Net unrealized gains of $2 million (after-tax) were recognized in Accumulated Other Comprehensive Loss on the Consolidated Balance Sheets as of December 31, 2017. The Rabbi Trust available-for-sale debt securities held as of December 31, 20172020 had the following maturities:
     
 Time Frame Fair Value 
   Millions 
 Less than one year $1
 
 1 - 5 years 37
 
 6 - 10 years 30
 
 11 - 15 years 5
 
 16 - 20 years 18
 
 Over 20 years 113
 
 Total Rabbi Trust Available-for-Sale Debt Securities $204
 
     
Time FrameFair Value
Millions
Less than one year$5 
1 - 5 years39 
6 - 10 years30 
11 - 15 years12 
16 - 20 years30 
Over 20 years119 
Total Rabbi Trust Available-for-Sale Debt Securities$235
 
PSEG periodically assesses individual debt securities whose fair value is less than amortized cost to determine whether the investments are considered to be other-than-temporarily impaired. For equity securities, the Rabbi Trust is invested in a commingled indexed mutual fund. Due to the commingled nature of this fund, PSEG does not have the ability to hold these securities until expected recovery. As a result, any declines in fair market value below cost are recorded as a charge to earnings. For fixed income securities, management considers its intent to sell or requirement to sell a security prior to expected recovery. In those cases where a sale is expected, any impairment would be recorded through earnings. For fixed income securities where there is no intent to sell or likely requirement to sell, management evaluates whether credit loss is a component of the impairment. If so, that portion is recorded through earnings while the noncredit loss component is recorded through Accumulated Other Comprehensive Income (Loss). Any subsequent recoveries of the noncredit loss component of the impairment would be recorded through Accumulated Other Comprehensive Income (Loss). Any subsequent recoveries of the credit loss component would be recognized through earnings. The assessment of fair market value compared to cost is applied on a weighted average basis taking into account various purchase dates and initial cost of the securities. In 2017, there were no other-than-temporary impairments recognized on investments of the Rabbi Trust.
The fair value of the Rabbi Trust related to PSEG, PSE&G and PSEG Power are detailed as follows:
As of December 31,As of December 31,
20202019
 Millions
PSE&G$51 $48 
PSEG Power66 62 
Other149 136 
Total Rabbi Trust Investments$266 $246 
       
   As of December 31, 2017 As of December 31, 2016 
   Millions 
 PSE&G $46
 $43
 
 Power 57
 53
 
 Other 128
 121
 
 Total Rabbi Trust Available-for-Sale Securities $231
 $217
 
       

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Note 10.12. Goodwill and Other Intangibles
In 2019, PSEG Power determined its fair value using a market-based enterprise valuation technique. Based on the results of the annual impairment test, PSEG Power determined that its entire goodwill was impaired and recorded a loss of $16 million in O&M Expense. The decrease in the fair value was primarily due to the continued decline in wholesale power market pricing.
As of December 31, 20172020 and 2016, Power had goodwill of $16 million related to the Bethlehem Energy Center facility. Power conducted an annual review for goodwill impairment in the fourth quarter of 2017 and concluded that goodwill continues to remain unimpaired. In addition to goodwill, as of December 31, 2017 and 2016,2019, PSEG Power had intangible assets of $114$158 million and $98$149 million,, respectively, related to emissions allowances and renewable energy credits.RECs. Emissions allowances and renewable energy creditsRECs are recorded at cost and evaluated for impairment at least annually. Emissions expense includes impairments of emissions allowances, if any, and costs for emissions, which is recorded as emissions occur. As load is served under contracts requiring energy from renewable sources, the related expense is recorded.
The changes to PSEG Power’s intangible assets during 20162019 and 20172020 are presented in the following table:as follows:
Emissions AllowancesRECsTotal Other Intangibles
Millions
Balance as of January 1, 2019$84 $59 $143 
Retirements(6)(83)(89)
Purchases26 72 98 
Sales and Transfers, net0 (3)(3)
Balance as of December 31, 2019$104 $45 $149 
Retirements(9)(93)(102)
Purchases17 94 111 
Balance as of December 31, 2020$112 $46 $158 
125
         
     
   Emissions Allowances Renewable Energy Credits Total Other Intangibles 
   Millions 
 Balance as of January 1, 2016 $62
 $40
 $102
 
 Retirements (6) (94) (100) 
 Purchases —
 99
 99
 
 Sales and Transfers, net (1) (1) (2) 
 Impairments (1) —
 (1) 
 Balance as of December 31, 2016 $54
 $44
 $98
 
 Retirements (7) (93) (100) 
 Purchases 27
 90
 117
 
 Sales and Transfers, net —
 (1) (1) 
 Balance as of December 31, 2017 $74
 $40
 $114
 
         

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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Note 11.13. Asset Retirement Obligations (AROs)
PSEG, PSE&G and PSEG Power recognize liabilities for the expected cost of retiring long-lived assets for which a legal obligation exists to remove or dispose of an asset or some component of an asset at retirement. These AROs are recorded at fair value in the period in which they are incurred and are capitalized as part of the carrying amount of the related long-lived assets. PSEG Power accretes the ARO liability to reflect the passage of time with the corresponding expense recorded in O&M. PSE&G, as a rate-regulated entity, recognizes regulatory assetsRegulatory Assets or liabilitiesLiabilities 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 Operation and Maintenance.
PSE&G has conditional AROs primarily for legal obligations related to the removal of treated wood poles and the requirement to seal natural gas pipelines at all sources of gas when the pipelines are no longer in service. PSE&G does not record an ARO for its protected steel and poly-based natural gas lines, as management believes that these categories of gas lines have an indeterminable life.
PSEG Power’s ARO liability primarily relates to the decommissioning of its nuclear power plants in accordance with NRC requirements. PSEG Power has an independent external trust that is intended to fund decommissioning of its nuclear facilities upon termination of operation. For additional information, see Note 9. Available-for-Sale Securities.11. Trust Investments. PSEG Power also identified conditional AROs primarily related to PSEG Power’s fossil generation units and solar facilities, including liabilities for removal of asbestos, ash ponds, stored hazardous liquid material and underground storage tanks from industrial power sites, and demolition of certain plants, and the restoration of the sites at which they reside, when the plants are no longer in service. To estimate the fair value of its AROs, PSEG Power uses a probability weighted, discounted cash flow model which, on a unit by unit basis, considers multiple outcome scenarios that include significant estimates and assumptions, and are based on third-party decommissioning cost estimates, cost escalation rates, inflation rates and discount rates.
Updated cost studies are obtained triennially unless new information necessitates more frequent updates. The most recent cost study was done in 2015.2018. When assumptions are revised to calculate fair values of existing AROs, generally, the ARO balance and corresponding long-lived asset are adjusted which impact the amount of accretion and depreciation expense recognized in future periods. For PSE&G, Regulatory Assets and Regulatory Liabilities result when accretion and amortization are adjusted to match rates established by regulators resulting in the regulatory deferral of any gain or loss.

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The changes to the ARO liabilities for PSEG, PSE&G and PSEG Power during 20162019 and 20172020 are presented in the following table:
PSEGPSE&GPSEG PowerOther
 Millions
ARO Liability as of January 1, 2019$1,063 $302 $758 $3 
Liabilities Settled(19)(18)(1)0 
Liabilities Incurred3 1 2 0 
Accretion Expense40 0 40 0 
Accretion Expense Deferred and Recovered in Rate Base (A)16 16 0 0 
Revision to Present Values of Estimated Cash Flows(16)2 (18)0 
ARO Liability as of December 31, 2019$1,087 $303 $781 $3 
Liabilities Settled(9)(7)(2)0 
Accretion Expense42 0 42 0 
Accretion Expense Deferred and Recovered in Rate Base (A)17 17 0 0 
Revision to Present Values of Estimated Cash Flows75 1 74 0 
ARO Liability as of December 31, 2020$1,212 $314 $895 $3 
(A)Not reflected as expense in Consolidated Statements of Operations
In early 2020, the NRC approved Peach Bottom’s second license extension for both units. Concurrent with the license extensions, PSEG Power has extended the useful life of the asset to match the 80-year life expectation and reassessed the related Asset Retirement Cost (ARC) and ARO assumptions. This resulted in an increase to the ARC asset and ARO liability of $74 million, primarily due to lower discount rates offset by a longer discounting period as a result of the Peach Bottom units’ longer expected useful life. In addition, PSEG Power reviewed its probabilities of early retirement on its nuclear units and concluded that no adjustments were necessary as of December 31, 2020.
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   PSEG PSE&G Power Other 
   Millions 
 ARO Liability as of January 1, 2016 $679
 $218
 $457
 $4
 
 Liabilities Settled (13) (9) (4) —
 
 Liabilities Incurred 25
 2
 23
 —
 
 Accretion Expense 26
 —
 26
 —
 
 Accretion Expense Deferred and Recovered in Rate Base (A) 12
 12
 —
 —
 
 Revision to Present Values of Estimated Cash Flows (3) (10) 9
 (2) 
 ARO Liability as of December 31, 2016 $726
 $213
 $511
 $2
 
 Liabilities Settled (29) (8) (21) —
 
 Liabilities Incurred 1
 —
 1
 —
 
 Accretion Expense 30
 —
 30
 —
 
 Accretion Expense Deferred and Recovered in Rate Base (A) 12
 12
 —
 —
 
 Revision to Present Values of Estimated Cash Flows 284
 (5) 289
 —
 
 ARO Liability as of December 31, 2017 $1,024
 $212
 $810
 $2
 
           
(A)Not reflected as expense in Consolidated Statements of Operations
During 2017, PSE&G recorded a reduction to its ARO liabilitiesIn 2019, PSEG Power’s decrease of $18 million was primarily due to the impactsale of settlementsits interests in the Keystone and changes to cash flow estimates.Conemaugh units. These changes had noan immaterial impact in PSE&G’sPSEG Power’s Consolidated Statement of Operations.
During 2017, Power recorded an increase to its ARO liabilities primarily due to a higher assumed probability of early retirement of its nuclear units of $276 million (SeeOperations. See Note 3.4. Early Plant RetirementsRetirements/Asset Dispositions for additional information).information.
Note 12.14. Pension, Other Postretirement Benefits (OPEB) and Savings Plans
PSEG sponsors and Services administers qualified and nonqualified pension plans and OPEB plans covering PSEG’s and its participating affiliates’ current and former employees who meet certain eligibility criteria. Eligible employees participate in non-contributoryPSEG’s qualified pension plans consist of two qualified defined benefit pension plans, Pension Plan and OPEBPension Plan II. Each of the qualified pension plans sponsored by PSEGinclude a Final Average Pay and administered by Services.two Cash Balance components. In addition, represented and nonrepresentednon-represented employees are eligible for participation in PSEG’s two2 defined contribution plans described below.plans.
PSEG, PSE&G and PSEG Power are required to record the under or over funded positions of their defined benefit pension and OPEB plans on their respective balance sheets. Such funding positions of each PSEG company are required to be measured as of the date of its respective year-end Consolidated Balance Sheets. For underfunded plans, the liability is equal to the difference between the plan’s benefit obligation and the fair value of plan assets. For defined benefit pension plans, the benefit obligation is the projected benefit obligation. For OPEB plans, the benefit obligation is the accumulated postretirement benefit obligation. In addition, GAAP requires that the total unrecognized costs for defined benefit pension and OPEB plans be recorded as an after-tax charge to Accumulated Other Comprehensive Income (Loss), a separate component of Stockholders’ Equity. However, for PSE&G, because the amortization of the unrecognized costs is being collected from customers, the accumulated unrecognized costs are recorded as a Regulatory Asset. The unrecognized costs represent actuarial gains or losses and prior service costs which hadhave not been expensed.
For PSE&G, the Regulatory Asset is amortized and recorded as net periodic pension cost in the Consolidated Statements of Operations. For PSEG Power, the charge to Accumulated Other Comprehensive Income (Loss) is amortized and recorded as net periodic pension cost in the Consolidated Statements of Operations.
In late June 2019, PSEG approved a plan amendment to its qualified pension plan, effective July 1, 2019. The amendment involved the spin-off of predominantly active participants from the existing qualified pension plan (Pension Plan) into a new qualified pension plan (Pension Plan II). Benefits offered to the plan participants remain unchanged. The existing plan’s pension benefit obligations, as well as the asset values, were remeasured as of July 1, 2019 as a result of the amendment. As of December 31, 2016, PSEG merged its three qualified defined benefit pension plans (excluding Servco plans) into one plan, thereby also merging all ofJuly 1, 2019, the pension plans’ assets. As a result, the total net periodic benefit costs, net of amounts capitalized, decreased by approximately $48 millionweighted average discount rate for the year ended December 31, 2017, as comparedcombined plans decreased from 4.41% to 3.65% and the 2017 amounts that would have been recognized had the plans not been merged. This is due to the amortization period forexpected long-term rate of return on plan assets remained at 7.80%. Actuarial gains and losses forassociated with the merged plan resulting in lower amortization than thatPension Plan will be amortized over the average remaining life expectancy of the individual plans. No changes were madeinactive participants (as opposed to the benefit formulas, vesting provisions, oraverage remaining service of active participants prior to the employees covered byplan being split). Actuarial gains and losses associated with Pension Plan II will be amortized over the plans.average remaining service of active participants. The combined remeasured qualified pension plans’ projected benefit obligation as of July 1, 2019 was $6.4 billion.
Amounts for Servco are not included in any of the following pension and OPEB benefit information for PSEG and its affiliates but rather are separately disclosed later in this note.

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The following table provides a roll-forward of the changes in the benefit obligation and the fair value of plan assets during each of the two years in the periods ended December 31, 20172020 and 2016.2019. It also provides the funded status of the plans and the amounts recognized and amounts not recognized on the Consolidated Balance Sheets at the end of both years.
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   Pension Benefits Other Benefits 
   2017 2016 2017 2016 
   Millions 
 Change in Benefit Obligation         
 Benefit Obligation at Beginning of Year (A) $5,772
 $5,522
 $1,754
 $1,612
 
 Service Cost 114
 109
 17
 17
 
 Interest Cost 204
 202
 63
 59
 
 Actuarial (Gain) Loss 564
 219
 199
 127
 
 Gross Benefits Paid (295) (282) (57) (57) 
 Plan Amendments —
 2
 —
 (4) 
 Benefit Obligation at End of Year (A) $6,359
 $5,772
 $1,976
 $1,754
 
 Change in Plan Assets         
 Fair Value of Assets at Beginning of Year $5,193
 $5,039
 $420
 $374
 
 Actual Return on Plan Assets 903
 403
 77
 32
 
 Employer Contributions 11
 33
 71
 71
 
 Gross Benefits Paid (295) (282) (57) (57) 
 Fair Value of Assets at End of Year $5,812
 $5,193
 $511
 $420
 
 Funded Status         
 Funded Status (Plan Assets less Benefit Obligation) $(547) $(579) $(1,465) $(1,334) 
 Additional Amounts Recognized in the Consolidated Balance Sheets         
 Current Accrued Benefit Cost (10) (11) (10) (10) 
 Noncurrent Accrued Benefit Cost (537) (568) (1,455) (1,324) 
 Amounts Recognized $(547) $(579) $(1,465) $(1,334) 
 Additional Amounts Recognized in Accumulated Other Comprehensive Income (Loss), Regulated Assets and Deferred Assets (B)   
 Prior Service Cost $(46) $(63) $(3) $(14) 
 Net Actuarial Loss 1,721
 1,763
 629
 523
 
 Total $1,675
 $1,700
 $626
 $509
 
           
 Pension BenefitsOther Benefits
 2020201920202019
 Millions
Change in Benefit Obligation
Benefit Obligation at Beginning of Year (A)$6,892 $5,921 $1,285 $1,203 
Service Cost141 123 9 10 
Interest Cost192 218 34 45 
Actuarial (Gain) Loss (B)615 955 32 109 
Gross Benefits Paid(333)(325)(50)(82)
Plan Amendments0 0 (4)0 
Benefit Obligation at End of Year (A)$7,507 $6,892 $1,306 $1,285 
Change in Plan Assets
Fair Value of Assets at Beginning of Year$5,929 $5,120 $540 $488 
Actual Return on Plan Assets761 1,122 70 107 
Employer Contributions11 12 4 27 
Gross Benefits Paid(333)(325)(50)(82)
Fair Value of Assets at End of Year$6,368 $5,929 $564 $540 
Funded Status
Funded Status (Plan Assets less Benefit Obligation)$(1,139)$(963)$(742)$(745)
Additional Amounts Recognized in the Consolidated Balance Sheets
Current Accrued Benefit Cost$(11)$(11)$(12)$(11)
Noncurrent Accrued Benefit Cost(1,128)(952)(730)(734)
Amounts Recognized$(1,139)$(963)$(742)$(745)
Additional Amounts Recognized in Accumulated Other Comprehensive Income (Loss), Regulated Assets and Deferred Assets (C)
Prior Service Credit$0 $(10)$(310)$(433)
Net Actuarial Loss2,354 2,150 364 409 
Total$2,354 $2,140 $54 $(24)
(A)Represents projected benefit obligation for pension benefits and the accumulated postretirement benefit obligation for other benefits. The vested benefit obligation is the actuarial present value of the vested benefits to which the employee is currently entitled but based on the employee’s expected date of separation of retirement.
(B)Includes $683 million ($406 million, after-tax) and $679 million ($398 million, after-tax) in Accumulated Other Comprehensive Loss related to Pension and OPEB as of December 31, 2017 and 2016, respectively. Also includes Regulatory Assets of $1,485 million and Deferred Assets of $133 million as of December 31, 2017 and Regulatory Assets of $1,396 million and Deferred Assets of $134 million as of December 31, 2016.
(A)Represents projected benefit obligation for pension benefits and the accumulated postretirement benefit obligation for other benefits. The vested benefit obligation is the actuarial present value of the vested benefits to which the employee is currently entitled but based on the employee’s expected date of separation or retirement.
(B)For pension benefits, the net actuarial loss was primarily due to a decrease in the discount rate. For OPEB, the net actuarial loss was primarily due to a decrease in the discount rate, partially offset by actuarial gains driven by lower than expected claims experience.
(C)Includes $760 million ($545 million, after-tax) and $695 million ($499 million, after-tax) in Accumulated Other Comprehensive Loss related to Pension and OPEB as of December 31, 2020 and 2019, respectively. Also includes Regulatory Assets of $1,489 million and Deferred Assets of $159 million as of December 31, 2020 and Regulatory Assets of $1,284 million and Deferred Assets of $137 million as of December 31, 2019.
The pension benefits table above provides information relating to the funded status of the qualified and nonqualified pension and OPEB plans on an aggregate basis. As of December 31, 2017,2020, PSEG had funded approximately 91%85% of its projected pension benefit obligation. This percentage does not include $231$266 million of assets in the Rabbi Trust as of December 31, 20172020 which were used partially to fund the nonqualified pension plans. As of December 31, 2017,2020, the nonqualified pension plans included in the projected benefit obligation in the above table were $167$182 million. The fair values of the Rabbi Trust assets are included in Other Special Funds on the Consolidated Balance Sheets.

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Accumulated Benefit Obligation
The accumulated benefit obligation for all PSEG’s defined benefit pension plans was $6.1$7.3 billion as of December 31, 20172020 and $5.6$6.7 billion as of December 31, 2016.2019.
The following table provides the components of net periodic benefit cost relating to all qualified and nonqualified pension and OPEB plans on an aggregate basis for PSEG, excluding Servco for the years ended December 31, 2017, 20162020, 2019 and 2015.2018.
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   Pension Benefits Years Ended December 31, Other Benefits Years Ended December 31, 
   2017 2016 2015 2017 2016 2015 
   Millions 
 Components of Net Periodic Benefit Cost             
 Service Cost $114
 $109
 $123
 $17
 $17
 22
 
 Interest Cost 204
 202
 234
 63
 59
 67
 
 Expected Return on Plan Assets (394) (394) (414) (34) (31) (31) 
 Amortization of Net             
 Prior Service Credit (18) (19) (19) (11) (14) (14) 
 Actuarial Loss 97
 158
 150
 51
 40
 43
 
 Net Periodic Benefit Cost $3
 $56
 $74
 $86
 $71
 $87
 
               
Amounts shown do not reflect the impacts of capitalization and co-owner allocations. Only the service cost component is eligible for capitalization, when applicable.
 Pension Benefits Years Ended December 31,Other Benefits Years Ended December 31,
202020192018202020192018
 Millions
Components of Net Periodic Benefit (Credits) Costs
Service Cost (included in O&M Expense)$141 $123 $130 $9 $10 $18 
Non-Service Components of Pension and OPEB (Credits) Costs
Interest Cost192 218 208 34 45 66 
Expected Return on Plan Assets(443)(408)(441)(39)(36)(41)
Amortization of Net
Prior Service Credit(10)(18)(18)(128)(128)(1)
Actuarial Loss92 96 85 47 50 64 
Non-Service Components of Pension and OPEB (Credits) Costs(169)(112)(166)(86)(69)88 
Total Benefit (Credits) Costs$(28)$11 $(36)$(77)$(59)$106 
Pension costs and OPEB costs for PSEG, PSE&G and PSEG Power are detailed as follows:
               
   
Pension Benefits
Years Ended December 31,
 
Other Benefits
Years Ended December 31,
 
   2017 2016 2015 2017 2016 2015 
   Millions 
 PSE&G $(4) $29
 $40
 $54
 $43
 $55
 
 Power 1
 16
 21
 27
 23
 27
 
 Other 6
 11
 13
 5
 5
 5
 
 Total Benefit Cost $3
 $56
 $74
 $86
 $71
 $87
 
               
 Pension Benefits
Years Ended December 31,		Other Benefits
Years Ended December 31,
 202020192018202020192018
 Millions
PSE&G$(27)$0 $(31)$(76)$(62)$68 
PSEG Power(5)4 (9)0 3 32 
Other4 7 4 (1)0 6 
Total Benefit (Credits) Costs$(28)$11 $(36)$(77)$(59)$106 
The following table provides the pre-tax changes recognized in Accumulated Other Comprehensive Income (Loss), Regulatory Assets and Deferred Assets:
 PensionOPEB
 2020201920202019
 Millions
Net Actuarial (Gain) Loss in Current Period$296 $241 $2 $39 
Amortization of Net Actuarial Gain (Loss)(92)(96)(47)(50)
Prior Service Cost (Credit) in Current Period0 0 (5)0 
Amortization of Prior Service Credit10 18 128 128 
Total$214 $163 $78 $117 
           
   Pension OPEB 
   2017 2016 2017 2016 
   Millions 
 Net Actuarial (Gain) Loss in Current Period $55
 $211
 $156
 $125
 
 Amortization of Net Actuarial Gain (Loss) (97) (158) (50) (40) 
 Prior Service Cost (Credit) in current period —
 1
 —
 (3) 
 Amortization of Prior Service Credit 18
 19
 11
 14
 
 Total $(24) $73
 $117
 $96
 
           



0
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Amounts that are expected to be amortized from Accumulated Other Comprehensive Loss, Regulatory Assets and Deferred Assets into Net Periodic Benefit Cost in 2018 are as follows:

       
   
Pension
Benefits
 
Other
Benefits
 
   2018 2018 
   Millions 
 Actuarial Loss $85
 $64
 
 Prior Service Credit $(18) $(1) 
       
The following assumptions were used to determine the benefit obligations and net periodic benefit costs:
               
   Pension Benefits Other Benefits 
   2017 2016 2015 2017 2016 2015 
 Weighted-Average Assumptions Used to Determine Benefit Obligations as of December 31   
 Discount Rate 3.73% 4.29% 4.54% 3.76% 4.37% 4.58% 
 Rate of Compensation Increase 3.90% 3.61% 3.61% 3.90% 3.61% 3.61% 
 Weighted-Average Assumptions Used to Determine Net Periodic Benefit Cost for Years Ended December 31   
 Discount Rate 4.29% 4.54% 4.20% 4.37% 4.58% 4.21% 
 Service Cost Interest Rate 4.53% 4.81% 4.20% 4.64% 4.87% 4.21% 
 Interest Cost Interest Rate 3.63% 3.75% 4.20% 3.69% 3.76% 4.21% 
 Expected Return on Plan Assets 7.80% 8.00% 8.00% 7.80% 8.00% 8.00% 
 Rate of Compensation Increase 3.61% 3.61% 3.61% 3.61% 3.61% 3.61% 
 Assumed Health Care Cost Trend Rates as of December 31         
 Health Care Costs             
 Immediate Rate       7.93% 7.55% 7.75% 
 Ultimate Rate       4.75% 4.75% 4.75% 
 Year Ultimate Rate Reached       2026
 2025
 2025
 
         Millions 
 Effect of a 1% Increase in the Assumed Rate of Increase in Health Care Benefit Costs   
 Total of Service Cost and Interest Cost       $13
 $11
 $12
 
 Postretirement Benefit Obligation       $240
 $191
 $194
 
 Effect of a 1% Decrease in the Assumed Rate of Increase in Health Care Benefit Costs   
 Total of Service Cost and Interest Cost       $(10) $(9) $(10) 
 Postretirement Benefit Obligation       $(198) $(160) $(160) 
               
 Pension BenefitsOther Benefits
 202020192018202020192018
Weighted-Average Assumptions Used to Determine Benefit Obligations as of December 31
Discount Rate2.61 %3.30 %4.41 %2.46 %3.20 %4.31 %
Rate of Compensation Increase4.40 %3.90 %3.90 %4.40 %3.90 %3.90 %
Cash Balance Interest Crediting Rate6.00 %6.00 %6.00 %N/AN/AN/A
Weighted-Average Assumptions Used to Determine Net Periodic Benefit Cost for Years Ended December 31
Discount Rate3.30 %4.41 %3.73 %3.20 %4.31 %3.76 %
Service Cost Interest Rate3.49 %4.58 %3.88 %3.50 %4.48 %3.90 %
Interest Cost Interest Rate2.87 %4.03 %3.35 %2.87 %3.91 %3.39 %
Expected Return on Plan Assets7.70 %7.80 %7.80 %7.70 %7.79 %7.80 %
Rate of Compensation Increase3.90 %3.90 %3.90 %3.90 %3.90 %3.90 %
Cash Balance Interest Crediting Rate6.00 %6.00 %6.00 %N/AN/AN/A
Assumed Health Care Cost Trend Rates as of December 31
Health Care Costs
Immediate Rate6.37 %6.68 %7.28 %
Ultimate Rate4.75 %4.75 %4.75 %
Year Ultimate Rate Reached202920292026
Plan Assets
The investments of pension and OPEB plans are held in a trust account by the Trustee and consist of an undivided interest in an investment account of the Master Trust. The investments in the pension and OPEB plans are measured at fair value within a hierarchy that prioritizes the inputs to fair value measurements into three levels. See Note 17.19. Fair Value Measurements for more information on fair value guidance. Use of the Master Trust permits the commingling of pension plan assets and OPEB plan assets for investment and administrative purposes. Although assets of the plans are commingled in the Master Trust, the Trustee maintains supporting records for the purpose of allocating the net gain or loss of the investment account to the respective participating plans. The net investment income of the investment assets is allocated by the Trustee to each participating plan based on the relationship of the interest of each plan to the total of the interests of the participating plans. As of December 31, 2017,2020, the pension plan interest and OPEB plan interest in such assets of the Master Trust were approximately 92% and 8%, respectively.

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The following tables present information about the investments measured at fair value on a recurring basis as of December 31, 20172020 and 2016,2019, including the fair value measurements and the levels of inputs used in determining those fair values.
130
           
   Recurring Fair Value Measurements as of December 31, 2017 
     
Quoted Market Prices
for Identical Assets
 
Significant Other
Observable Inputs
 
Significant
Unobservable Inputs
 
 Description Total (Level 1) (Level 2) (Level 3) 
   Millions 
 Cash Equivalents (A) $133
 $117
 $16
 $—
 
 Equity Securities 

       
   Common Stock (B) 1,275
 1,275
 —
 —
 
   Commingled (C) 1,401
 1,218
 183
 —
 
   Preferred Stock (B) 6
 6
 —
 —
 
 Debt Securities (D) 

       
   U.S. Treasury 571
 —
 571
 —
 
   Government—Other 272
 —
 272
 —
 
   Corporate 963
 —
 963
 —
 
 Subtotal Fair Value $4,621
 $2,616
 $2,005
 $—
 
 Measured at net asset value practical expedient         
 Commingled—Equities (E) 1,675
       
 Private Equity (F) 14
       
 Total Fair Value (G) $6,310
 

 

 

 
           
           
   Recurring Fair Value Measurements as of December 31, 2016 
     
Quoted Market Prices
for Identical Assets
 
Significant Other
Observable Inputs
 
Significant
Unobservable Inputs
 
 Description Total (Level 1) (Level 2) (Level 3) 
   Millions 
 Cash Equivalents (A) $107
 $105
 $2
 $—
 
 Equity Securities 

       
   Common Stock (B) 944
 944
 —
 —
 
   Commingled (C) 1,387
 1,247
 140
 —
 
   Preferred Stock (B) 1
 1
 —
 —
 
 Debt Securities (D) 

       
   U.S. Treasury 441
 —
 441
 —
 
   Government—Other 263
 —
 263
 —
 
   Corporate 836
 —
 836
 —
 
 Subtotal Fair Value $3,979
 $2,297
 $1,682
 $—
 
 Measured at net asset value practical expedient         
 Commingled—Equities (E) 1,604
       
 Private Equity (F) 16
       
 Total Fair Value (G) $5,599
 

 

 

 
           

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(A)The Collective Investment Fund publishes a daily net asset value (NAV) which participants may use for daily redemptions without restrictions (Level 1). Certain temporary investments are valued using inputs such as time-to-maturity, coupon rate, quality rating and current yield (Level 2).
(B)Common stocks and preferred stocks are measured using observable data in active markets and considered Level 1.
(C)Commingled Funds that allow daily redemption at their daily published NAV without restrictions are classified as Level 1. Commingled Funds that publish daily NAV but with certain near term redemption restrictions which prevent redemption at the published daily NAV are classified as Level 2.
(D)Debt securities include mainly investment grade corporate and municipal bonds, US Treasury obligations and Federal Agency asset-backed securities with a wide range of maturities. These investments are valued using an evaluated pricing approach that varies by asset class and reflects observable market information such as the most recent exchange price or quoted bid for similar securities. Market-based standard inputs typically include benchmark yields, reported trades, broker/dealer quotes and issuer spreads or the most recent quoted for similar securities which are a Level 2 measure.
(E)In 2016, as part of the implementation of the accounting guidance on investments measured at fair value using NAV as a practical expedient, certain commingled equity funds have been removed from the fair value hierarchy as they are measured at fair value using the NAV per share (or its equivalent) practical expedient. These funds do not meet the definition of readily determinable fair value due to limitations in published NAV (last business day of the month) and include certain redemption restrictions ranging from five to fifteen days advance notice prior to redemption days and limitations on withdrawals over 25% of the total fund. The objectives of these funds are mainly tracking the S&P Index or achieving long-term growth through investment in foreign equity securities and the MSCI Emerging Markets Index.
(F)Private equity investments primarily include various limited partnerships that invest in either operating companies through acquisitions or developing a portfolio of non-US distressed investments to maximize total return on capital. These investments are valued at NAV (or its equivalent) on an annual basis and have significant redemption restrictions preventing redemption until fund liquidation and limited ability to sell these investments. Fund liquidation is not expected to occur for several more years. These investments have been removed from the fair value hierarchy in accordance with the guidance on NAV practical expedient.
(G)
Excludes net receivable of $13 million and $14 million at December 31, 2017 and 2016, respectively, which consists of interest, dividends and receivables and payables related to pending securities sales and purchases.
 Recurring Fair Value Measurements as of December 31, 2020
 Quoted Market Prices
for Identical Assets		Significant Other
Observable Inputs		Significant
Unobservable Inputs
DescriptionTotal(Level 1)(Level 2)(Level 3)
 Millions
Cash Equivalents (A)$85 $85 $0 $0 
Equity Securities
  Common Stock (B)1,763 1,763 0 0 
  Commingled (C)1,964 1,025 939 0 
  Preferred Stock (B)10 10 0 0 
  Other (D)1 1 0 0 
Debt Securities (E)
  U.S. Treasury419 0 419 0 
  Government—Other258 0 258 0 
  Corporate823 0 823 0 
 Commingled4 4 0 0 
Subtotal Fair Value$5,327 $2,888 $2,439 $0 
Measured at net asset value practical expedient
Commingled—Equities (F)1,283 
Real Estate Investment (G)306 
Private Equity (H)5 
Total Fair Value (I)$6,921 
Recurring Fair Value Measurements as of December 31, 2019
 Quoted Market Prices
for Identical Assets		Significant Other
Observable Inputs		Significant
Unobservable Inputs
DescriptionTotal(Level 1)(Level 2)(Level 3)
 Millions
Cash Equivalents (A)$104 $103 $1 $0 
Equity Securities
  Common Stock (B)1,487 1,487 0 0 
  Commingled (C)1,707 1,042 665 0 
  Preferred Stock (B)19 19 0 0 
  Other (D)3 3 0 0 
Debt Securities (E)
  U.S. Treasury544 0 544 0 
  Government—Other284 0 284 0 
  Corporate837 0 837 0 
Commingled3 3 0 0 
Other (Future Contracts)(3)(3)0 0 
Subtotal Fair Value$4,985 $2,654 $2,331 $0 
Measured at net asset value practical expedient
Commingled—Equities (F)1,154 
Real Estate Investment (G)302 
Private Equity (H)8 
Total Fair Value (I)$6,449 

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(A)The Collective Investment Fund publishes a daily net asset value (NAV) which participants may use for daily redemptions without restrictions (Level 1). Certain temporary investments are valued using inputs such as time-to-maturity, coupon rate, quality rating and current yield (Level 2).
(B)Common stocks and preferred stocks are measured using observable data in active markets and considered Level 1.
(C)Commingled Funds that allow daily redemption at their daily published NAV without restrictions are classified as Level 1. Commingled Funds that publish daily NAV but with certain near-term redemption restrictions which prevent redemption at the published daily NAV are classified as Level 2.
(D)Investment in a publicly traded limited partnership.
(E)Debt securities include mainly investment grade corporate and municipal bonds, U.S. Treasury obligations and Federal Agency asset-backed securities with a wide range of maturities. These investments are valued using an evaluated pricing approach that varies by asset class and reflects observable market information such as the most recent exchange price or quoted bid for similar securities. Market-based standard inputs typically include benchmark yields, reported trades, broker/dealer quotes and issuer spreads or the most recent quotes for similar securities which are a Level 2 measure.
(F)Certain commingled equity funds are not included in the fair value hierarchy as they are measured at fair value using the NAV per share (or its equivalent) practical expedient. These funds do not meet the definition of readily determinable fair value due to the frequency of publishing NAV (monthly). The objectives of these funds are mainly tracking the S&P Index or achieving long-term growth through investment in foreign equity securities and the Morgan Stanley Capital International Index.
(G)The unlisted real estate fund invests in office, apartment, industrial and retail space. The fund is valued using the NAV per unit of funds. The investment value of the real estate properties is determined on a quarterly basis by independent market appraisers engaged by the board of directors of the fund. The ability to redeem funds is subject to the availability of cash arising from net investment income, allocations and the sale of investments in the normal course of business. The fund’s NAV is published quarterly. In addition, redemptions require one quarter advance notice prior to redemption and are fulfilled quarterly. The fund, therefore, does not meet the definition of readily determinable fair value. The purpose of the fund is to acquire, own, hold for investment and ultimately dispose of investments in real estate and real estate-related assets with the intention of achieving current income, capital appreciation or both.
(H)Private equity investments primarily include various limited partnerships that invest in either operating companies through acquisitions or developing a portfolio of non-U.S. distressed investments to maximize total return on capital. These investments are valued at NAV (or its equivalent) on a quarterly basis and have significant redemption restrictions preventing redemption until fund liquidation and limited ability to sell these investments. Fund liquidation is not expected to occur for several more years. These investments are not included in the fair value hierarchy in accordance with the guidance on NAV practical expedient.
(I)Excludes net receivables of $10 million and $15 million as of December 31, 2020 and 2019, respectively, which consist of interest, dividends and receivables and payables related to pending securities sales and purchases. In addition, the table excludes cash and foreign currency of $1 million and $5 million as of December 31, 2020 and 2019, respectively.
The following table provides the percentage of fair value of total plan assets for each major category of plan assets held for the qualified pension and OPEB plans as of the measurement date, December 31:
       
   As of December 31, 
 Investments 2017 2016 
 Equity Securities 69% 70% 
 Debt Securities 29
 28
 
 Other Investments 2
 2
 
 Total Percentage 100% 100% 
       
 As of December 31,
Investments20202019
Equity Securities72 %68 %
Debt Securities22 26 
Other Investments6 6 
Total Percentage100 %100 %
PSEG utilizes forecasted returns, risk, and correlation of all asset classes in order to develop a portfolio designed to produce the maximum return opportunity per unit of risk.an efficient portfolio. PSEG’s latest asset/liability study indicates that a long-term target asset allocation of 70%59% equities, 18% real assets and 30%23% fixed income is consistent with the funds’ financial objectives. Certain investments in real assets are made through investing in equity securities and tracked as equities when reporting fair value; however, they are viewed by their asset class, real assets, in our target asset allocation. Derivative financial instruments are used by the plans’ investment managers primarily to adjust the fixed income duration of the portfolio and hedge the currency risk component of foreign investments. The expected long-term rate of
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return on plan assets was 7.8%7.7% for 20172020 and will be 7.8%the same for 2018.2021. This expected return was determined based on the study discussed above, including a premium for active management and considered the plans’ historical annualized rate of return since inception.
Plan Contributions
PSEG has no planned contributionsdoes not plan to contribute to its pension and OPEB plans in 2018. PSEG2021. IRS minimum funding requirements for pension plans are determined based on the fund’s assets and liabilities at the end of a calendar year for the subsequent calendar year. As a result, the market volatility in 2020 associated with the ongoing coronavirus pandemic is not expected to make discretionaryimpact PSEG’s pension contributions of $14 million into its OPEB plan during 2018.

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in 2021.
Estimated Future Benefit Payments
The following pension benefit and postretirement benefit payments are expected to be paid to plan participants.
        
 Year  
Pension
Benefits
 Other Benefits 
    Millions 
 2018  $337
 $88
 
 2019  331
 92
 
 2020  341
 96
 
 2021  352
 101
 
 2022  364
 105
 
 2023-2027  1,954
 560
 
 Total  $3,679
 $1,042
 
        
YearPension
Benefits		Other Benefits
 Millions
2021$389 $83 
2022368 84 
2023381 84 
2024392 84 
2025401 83 
2026-20302,119 388 
Total$4,050 $806 
401(k) Plans
PSEG sponsors two2 401(k) plans, which are defined contribution retirement plans subject to the Employee Retirement Income Security Act (ERISA) defined contribution retirement plans.. Eligible represented employees of PSEG’s subsidiaries participate in the PSEG Employee Savings Plan (Savings Plan), while eligible non-represented employees of PSEG’s subsidiaries participate in the PSEG Thrift and Tax-Deferred Savings Plan (Thrift Plan). Eligible employees may contribute up to 50% of their annual eligible compensation to these plans, not to exceed the IRS maximums, including any catch-up contributions for those employees age 50 and above. PSEG matches 50% of such employee contributions up to 7% of pay for Savings Plan participants and up to 8% of pay for Thrift Plan participants.
The amountamounts paid for employer matching contributions to the plans for PSEG, PSE&G and PSEG Power are detailed as follows:
         
   Thrift Plan and Savings Plan 
   Years Ended December 31, 
   2017 2016 2015 
   Millions 
 PSE&G $25
 $24
 $22
 
 Power 11
 12
 12
 
 Other 5
 5
 5
 
 Total Employer Matching Contributions $41
 $41
 $39
 
         
Thrift Plan and Savings Plan
Years Ended December 31,
 202020192018
 Millions
PSE&G$27 $25 $26 
PSEG Power10 10 10 
Other6 5 5 
Total Employer Matching Contributions$43 $40 $41 
Servco Pension and OPEB
At the direction of LIPA, effective January 1, 2014, Servco established benefit plans that provide substantially the same benefits tosponsors a qualified pension plan and OPEB plan covering its employees as those previously provided by National Grid Electric Services LLC (NGES), the predecessor T&D system manager for LIPA. Since the vast majority of Servco’s employees had worked under NGES’ T&D operations services arrangement with LIPA, Servco’s plans providewho meet certain of those employees with pension and OPEB vested credit for prior years’ services earned while working for NGES. The benefit plans cover all employees of Servco for current service.eligibility criteria. Under the OSA, all of these and any future employee benefit costs for these plans are to be funded by LIPA. See Note 4.5. Variable Interest Entity. These obligations, as well as the offsetting long-term receivable, are separately presented on the Consolidated Balance Sheet of PSEG.
The following table provides a roll-forward of the changes in Servco’s benefit obligation and the fair value of its plan assets during the years ended December 31, 20172020 and 2016.2019. It also provides the funded status of the plans and the amounts recognized and amounts not recognized on the Consolidated Balance Sheets at the end of both years.

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   Pension Benefits Other Benefits 
   2017 2016 2017 2016 
     Millions 
 Change in Benefit Obligation         
 Benefit Obligation at Beginning of Year $262
 $211
 $452
 $375
 
 Service Cost 27
 24
 15
 12
 
 Interest Cost 11
 9
 19
 17
 
 Actuarial (Gain) Loss 22
 14
 60
 50
 
 Gross Benefits Paid (2) (1) (4) (2) 
 Plan Amendments —
 5
 —
 —
 
 Benefit Obligation at End of Year (A) $320
 $262
 $542
 $452
 
 Change in Plan Assets         
 Fair Value of Assets at Beginning of Year $134
 $97
 $—
 $—
 
 Actual Return on Plan Assets 24
 10
 —
 —
 
 Employer Contributions 35
 28
 4
 2
 
 Gross Benefits Paid (2) (1) (4) (2) 
 Fair Value of Assets at End of Year $191
 $134
 $—
 $—
 
 Funded Status         
 Funded Status (Plan Assets less Benefit Obligation) $(129) $(128) $(542) $(452) 
 Additional Amounts Recognized in the Consolidated Balance Sheets         
 Accrued Pension Costs of Servco $(129) $(128) N/A
 N/A
 
 OPEB Costs of Servco N/A
 N/A
 (542) (452) 
 Amounts Recognized (B) $(129) $(128) $(542) $(452) 
           
 Pension BenefitsOther Benefits
 2020201920202019
 Millions
Change in Benefit Obligation
Benefit Obligation at Beginning of Year (A)$453 $321 $626 $501 
Service Cost33 26 20 16 
Interest Cost14 14 20 22 
Actuarial (Gain) Loss (B)74 96 42 96 
Gross Benefits Paid(5)(4)(9)(6)
Plan Amendments0 0 0 (3)
Benefit Obligation at End of Year (A)$569 $453 $699 $626 
Change in Plan Assets
Fair Value of Assets at Beginning of Year$282 $212 $0 $0 
Actual Return on Plan Assets36 46 0 0 
Employer Contributions30 28 9 6 
Gross Benefits Paid(5)(4)(9)(6)
Fair Value of Assets at End of Year$343 $282 $0 $0 
Funded Status
Funded Status (Plan Assets less Benefit Obligation)$(226)$(171)$(699)$(626)
Additional Amounts Recognized in the Consolidated Balance Sheets
Accrued Pension Costs of Servco$(226)$(171)N/AN/A
OPEB Costs of ServcoN/AN/A(699)(626)
Amounts Recognized (C)$(226)$(171)$(699)$(626)
(A)Represents projected benefit obligation for pension benefits and the accumulated postretirement benefit obligation for other benefits. The vested benefit obligation is the actuarial present value of the vested benefits to which the employee is currently entitled but based on the employee’s expected date of separation of retirement.
(B)Amounts equal to the accrued pension and OPEB costs of Servco are offset in Long-Term Receivable of VIE on PSEG’s Consolidated Balance Sheets.
(A)Represents projected benefit obligation for pension benefits and the accumulated postretirement benefit obligation for other benefits. The vested benefit obligation is the actuarial present value of the vested benefits to which the employee is currently entitled but based on the employee’s expected date of separation or retirement.
(B)For pension benefits, the net actuarial loss was primarily due to a decrease in the discount rate. For OPEB, the net actuarial loss in 2020 was primarily due to a decrease in the discount rate, partially offset by actuarial gains driven by lower than expected participation experience. The OPEB net actuarial loss in 2019 was primarily due to a decrease in the discount rate.
(C)Amounts equal to the accrued pension and OPEB costs of Servco are offset in Long-Term Receivable of VIE on PSEG’s Consolidated Balance Sheets.
Pension and OPEB costs of Servco are accounted for according to the OSA. Servco recognizes expenses for contributions to its pension plan trusts and for OPEB payments made to retirees. Operating Revenues are recognized for the reimbursement of these costs. The pension-related revenues and costs for 2017, 20162020, 2019 and 20152018 were $35$30 million, $28 million and $30$40 million, respectively. Servco has contributed its entire planned contribution amount to its pension plan trusts during 2017.2020. The OPEB-related revenues earned and costs incurred were $4$9 million, $6 million and $2$6 million in 20172020, 2019 and 2016, respectively, and immaterial for 2015.
2018, respectively. The following assumptions were used to determine the benefit obligations of Servco:
               
   Pension Benefits Other Benefits 
   2017 2016 2015 2017 2016 2015 
 Weighted-Average Assumptions Used to Determine Benefit Obligations as of December 31   
 Discount Rate 3.90% 4.61% 4.92% 3.96% 4.71% 4.97% 
 Rate of Compensation Increase 3.25% 3.25% 3.25% 3.25% 3.25% 3.25% 
 Assumed Health Care Cost Trend Rates as of December 31         
 Health Care Costs             
 Immediate Rate       7.69% 7.55% 7.55% 
 Ultimate Rate       4.75% 4.75% 4.75% 
 Year Ultimate Rate Reached       2026
 2025
 2025
 
         Millions 
 Effect of a 1% Increase in the Assumed Rate of Increase in Health Care Benefit Costs   
 Postretirement Benefit Obligation       $131
 $97
 $75
 
 Effect of a 1% Decrease in the Assumed Rate of Increase in Health Care Benefit Costs   
 Postretirement Benefit Obligation       $(99) $(75) $(60) 
               

 Pension BenefitsOther Benefits
 202020192018202020192018
Weighted-Average Assumptions Used to Determine Benefit Obligations as of December 31
Discount Rate2.98 %3.52 %4.60 %3.08 %3.60 %4.67 %
Rate of Compensation Increase3.95 %3.25 %3.25 %3.95 %3.25 %3.25 %
Cash Balance Interest Crediting Rate3.75 %3.75 %3.75 %N/AN/AN/A
Assumed Health Care Cost Trend Rates as of December 31
Health Care Costs
Immediate Rate6.70 %6.94 %8.03 %
Ultimate Rate4.75 %4.75 %4.75 %
Year Ultimate Rate Reached202920292026
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Plan Assets
All the investments of Servco’s pension plans are held in a trust account by the Trustee and consist of an undivided interest in an investment account of the Servco Master Trust. The investments in the pension are measured at fair value within a hierarchy that prioritizes the inputs to fair value measurements into three levels. See Note 17.19. Fair Value Measurements for more information on fair value guidance. The Actuary maintains supporting records for the purpose of allocating the net gain or loss of the investment account to the respective participating plans. The net investment income of the investment assets is allocated by the Actuary to each participating plan based on the relationship of the interest of each plan to the total of the interests of the participating plans.
The following tables present information about Servco’s investments measured at fair value on a recurring basis as of December 31, 20172020 and 2016,2019, including the fair value measurements and the levels of inputs used in determining those fair values.
 Recurring Fair Value Measurements as of December 31, 2020
 Quoted Market Prices
for Identical Assets		Significant Other
Observable Inputs		Significant
Unobservable Inputs
DescriptionTotal(Level 1)(Level 2)(Level 3)
 Millions
Cash Equivalents$1 $1 $0 $0 
Commingled Equities (A)259 0 259 0 
Commingled Bonds (A)83 0 83 0 
Total$343 $1 $342 $0 
           
   Recurring Fair Value Measurements as of December 31, 2017 
     
Quoted Market Prices
for Identical Assets
 
Significant Other
Observable Inputs
 
Significant
Unobservable Inputs
 
 Description Total (Level 1) (Level 2) (Level 3) 
   Millions 
 Commingled Equities (A) $137
 $—
 $137
 $—
 
 Commingled Bonds (A) 54
 —
 54
 —
 
 Total $191
 $—
 $191
 $—
 
           
 Recurring Fair Value Measurements as of December 31, 2019
 Quoted Market Prices
for Identical Assets		Significant Other
Observable  Inputs		Significant
Unobservable Inputs
DescriptionTotal(Level 1)(Level 2)(Level 3)
 Millions
Commingled Equities (A)
$202 $0 $202 $0 
Commingled Bonds (A)
80 0 80 0 
Total$282 $0 $282 $0 
(A)Investments in commingled equity and bond funds have a readily determinable fair value as they publish a daily NAV available to investors which is the basis for current transactions and contain certain redemption restrictions requiring advance notice of one to two days for withdrawals (Level 2).
           
   Recurring Fair Value Measurements as of December 31, 2016 
     
Quoted Market Prices
for Identical Assets
 
Significant Other
Observable Inputs
 
Significant
Unobservable Inputs
 
 Description Total (Level 1) (Level 2) (Level 3) 
   Millions 
 
Commingled Equities (A)

 $96
 $—
 $96
 $—
 
 
Commingled Bonds (A)

 38
 —
 38
 —
 
 Total $134
 $—
 $134
 $—
 
           
(A)Investments in commingled equity and bond funds have a readily determinable fair value as they publish a daily NAV available to investors which is the basis for current transactions and contain certain redemption restrictions requiring advance notice of one to two days for withdrawals (Level 2).
The following table provides the percentage of fair value of total plan assets for each major category of plan assets held for the qualified pension and OPEB plans of Servco as of the measurement date, December 31:
       
   As of December 31, 
 Investments 2017 2016 
 Equity Securities 72% 71% 
 Debt Securities 28
 29
 
 Total Percentage 100% 100% 
       
 As of December 31,
Investments20202019
Equity Securities76 %72 %
Debt Securities24 28 
Total Percentage100 %100 %
Servco utilizes forecasted returns, risk, and correlation of all asset classes in order to develop a portfolio designed to produce the maximum return opportunity per unit of risk.an efficient portfolio. The results from Servco’s latest asset/liability study indicated that a long-term target asset allocation of 70%60% equities, 15% real assets and 30%25% fixed income is consistent with the funds’ financial objectives. Certain investments in real assets are made through investing in equity securities and tracked as equities when reporting fair value; however, they are viewed by their asset class, real assets, in our target asset allocation. The expected long-term rate of return on plan assets was 7.6% for 20172020 and will be 7.6%the same for 2018.2021. This expected return was determined based on the study discussed above, including a premium for active management.


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Plan Contributions
Servco plans to contribute $40$37 million into its pension plan during 2018.2021. IRS minimum funding requirements for pension plans are determined based on the fund’s assets and liabilities at the end of a calendar year for the subsequent calendar year. As a result, the market volatility in 2020 associated with the ongoing coronavirus pandemic is not expected to impact Servco’s pension contributions in 2021.
Estimated Future Benefit Payments
The following pension benefit and postretirement benefit payments are expected to be paid to Servco’s plan participants:
        
 Year  
Pension
Benefits
 Other Benefits 
    Millions 
 2018  $3
 $4
 
 2019  4
 6
 
 2020  5
 8
 
 2021  7
 9
 
 2022  9
 12
 
 2023-2027  78
 87
 
 Total  $106
 $126
 
        

YearPension
Benefits		Other Benefits
 Millions
2021$8 $9 
202210 11 
202312 13 
202415 15 
202517 17 
2026-2030123 111 
Total$185 $176 
Servco 401(k) Plans
Servco sponsors two2 401(k) plans, which are defined contribution retirement plans subject to ERISA. Eligible non-represented employees of Servco participate in the Long Island Electric Utility Servco LLC Incentive Thrift Plan I (Thrift Plan I), and eligible represented employees of Servco participate in the Long Island Electric Utility Servco LLC Incentive Thrift Plan II (Thrift Plan II). Participants in the Plansplans may contribute up to 50% of their eligible compensation to these plans, not to exceed the IRS maximums, including any Catch-Up Contributionscatch-up contributions for those employees age 50 and above. Servco does not provide an employer match or core contribution for employees in Thrift Plan II. For employees in Thrift Plan I, Servco matches 50% of such employee contributions up to 8% of eligible compensation and provides core contributions (based on years of service and age) to employees who do not participate in Servco’s Retirement Income Plan. The amounts expensed by Servco for employer matching contributions for the years ended December 31, 2017, 20162020, 2019 and 20152018 were $6$9 million, $5$8 million and $4$7 million, respectively, and pursuant to the OSA, Servco recognizes Operating Revenues for the reimbursement of these costs.
Note 13.15. Commitments and Contingent Liabilities
Guaranteed Obligations
PSEG Power’s activities primarily involve the purchase and sale of energy and related products under transportation, physical, financial and forward contracts at fixed and variable prices. These transactions are with numerous counterparties and brokers that may require cash, cash-related instruments or guarantees as a form of collateral.
PSEG Power has unconditionally guaranteed payments to counterparties byon behalf of its subsidiaries in commodity-related transactions in order to
•support current exposure, interest and other costs on sums due and payable in the ordinary course of business, and
•obtain credit.
PSEG Power is subject to
•counterparty collateral calls related to commodity contracts of its subsidiaries, and
•certain creditworthiness standards as guarantor under performance guarantees of its subsidiaries.
Under these agreements, guarantees cover lines of credit between entities and are often reciprocal in nature. The exposure between counterparties can move in either direction.
In order for PSEG Power to incur a liability for the face value of the outstanding guarantees,
•its subsidiaries would have to
fully utilize the credit granted to them by every counterparty to whom PSEG Power has provided a guarantee, and
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•the net position of the related contracts would have to be “out-of-the-money” (if the contracts are terminated, PSEG Power would owe money to the counterparties).

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PSEG Power believes the probability of this result is unlikely. For this reason, PSEG Power believes that the current exposure at any point in time is a more meaningful representation of the potential liability under these guarantees. Current exposure consists of the net of accounts receivable and accounts payable and the forward value on open positions, less any collateral posted.
Changes in commodity prices can have a material impact on collateral requirements under such contracts, which are posted and received primarily in the form of cash and letters of credit. PSEG Power also routinely enters into futures and options transactions for electricity and natural gas as part of its operations. These futures contracts usually require a cash margin deposit with brokers, which can change based on market movement and in accordance with exchange rules.
In addition to the guarantees discussed above, PSEG Power has also provided payment guarantees to third parties and regulatory authorities on behalf of its affiliated companies. These guarantees support various other non-commodity related contractual obligations.
The following table shows the face value of PSEG Power’s outstanding guarantees, current exposure and margin positions as of December 31, 20172020 and 2016.
2019.
       
   As of December 31, 2017 As of December 31, 2016 
   Millions 
 Face Value of Outstanding Guarantees $1,701
 $1,806
 
 Exposure under Current Guarantees $153
 $139
 
       
 Letters of Credit Margin Posted $103
 $157
 
 Letters of Credit Margin Received $32
 $99
 
       
 Cash Deposited and Received     
 Counterparty Cash Margin Deposited $—
 $—
 
 Counterparty Cash Margin Received $(1) $(1) 
 Net Broker Balance Deposited (Received) $147
 $57
 
       
 Additional Amounts Posted     
 Other Letters of Credit $61
 $51
 
       
As of December 31, 2020As of December 31, 2019
 Millions
Face Value of Outstanding Guarantees$1,792 $1,854 
Exposure under Current Guarantees$128 $171 
Letters of Credit Margin Posted$128 $121 
Letters of Credit Margin Received$45 $29 
Cash Deposited and Received
Counterparty Cash Collateral Deposited$0 $0 
Counterparty Cash Collateral Received$(5)$(4)
Net Broker Balance Deposited (Received)$59 $48 
Additional Amounts Posted
Other Letters of Credit$42 $82 
As part of determining credit exposure, PSEG Power nets receivables and payables with the corresponding net fair values of energy contract balances.contracts. See Note 16.18. Financial Risk Management Activities for further discussion. In accordance with PSEG’s accounting policy, where it is applicable, cash (received)/deposited is allocated against derivative asset and liability positions with the same counterparty on the face of the Consolidated Balance Sheet. The remaining balances of net cash (received)/deposited after allocation are generally included in Accounts Payable and Receivable, respectively.
In addition to amounts for outstanding guarantees, current exposure and margin positions, PSEG and PSEG Power hadhave posted letters of credit to support PSEG Power’s various other non-energy contractual and environmental obligations. See the preceding table. In June 2017, Power sold its minority interest in PennEast and upon disposition, PSEG’s $106 million guarantee that had supported Power’s payment obligations related to PennEast was terminated.

Environmental Matters
Passaic River
Historic operations of PSEG companies and the operations of hundreds of other companies along theLower 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 as discussed as follows.
Federal Comprehensive Environmental Response, Compensation and Liability Act of 1980 (CERCLA)River Study Area    
The U.S. Environmental Protection Agency (EPA) has determined that a 17-mile stretch of the lower Passaic River from Newark to Clifton,(Lower Passaic River Study Area (LPRSA)) in New Jersey is a “Superfund” site under CERCLAthe Federal Comprehensive Environmental Response, Compensation and a comprehensive studyLiability Act of the entire 17 miles of the lower Passaic River needed to be performed.1980 (CERCLA). PSE&G and certain of its predecessors conducted operations at properties in this area, of the Passaic River. The properties included one operating electric generating station (Essex Site), whichincluding at 1 site that was transferred to Power, one former generating station and four former manufactured gas plant (MGP) sites.PSEG Power.

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In early 2007, certainCertain Potentially Responsible Parties (PRPs), including PSE&G and PSEG Power, formed a Cooperating Parties Group (CPG) and agreed to assume responsibility for conductingconduct a Remedial Investigation and Feasibility Study (RI/FS) of the 17 miles of the lower Passaic River.LPRSA. The CPG has agreed to allocate,allocated, on an interim basis, the associated costs of the RI/FS among its members on the basis of a mutually agreed upon formula. For the purpose of thismembers. The interim allocation is subject to change. In June 2019, the EPA conditionally
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approved the CPG’s Remedial Investigation. In December 2020, the EPA conditionally approved the CPG’s Feasibility Study, which has been revised as parties have exitedevaluated various adaptive management scenarios for the CPG, approximately 7.6 percentremediation of only the RI/FS costs are currently deemed attributable to PSE&G’s former MGP sites and approximately 1.9 percent is attributable to Power’s generating stations. These interim allocations are not binding on PSE&G or Power in terms of their respective shares of the costs that will be ultimately required to remediate the 17upper 9 miles of the lower Passaic River. PSEG has provided noticeLPRSA. The EPA’s selection of its preferred adaptive management scenario will be subject to insurers concerning this potential claim. Certain PRPs are currently involvedpublic review and comment prior to the EPA’s announcement of a final selection, which is expected in discussions with2021.
Separately, the EPA regarding cost allocations and related indemnification matters. We cannot predict the outcome of these discussions, or whether individual PRPs will be able to meet their obligations, either of which could havehas released a material impact on PSE&G’s and Power’s allocation of costs.
The CPG’s draft FS set forth various alternatives for remediating the lower Passaic River with an estimated cost to remediate the lower 17 miles of the Passaic River ranging from approximately $518 million to $3.2 billion on an undiscounted basis.
In March 2016, the EPA released its Record of Decision (ROD) for the EPA’s own Focused Feasibility Study (FFS) whichLPRSA’s lower 8.3 miles that requires the removal of 3.5 million cubic yards of sediment from the Passaic River’s lower 8.3 milessediments at an estimated cost of $2.3 billion on an undiscounted basis (ROD Remedy). An EPA-commenced process to allocate the associated costs is underway and PSEG cannot predict the outcome. The allocation does not address certain costs incurred by the EPA estimates the total project lengthfor which they may be entitled to reimbursement and which may be about 11 years, including a one year period of negotiation with the PRPs, three to four years to design the project and six years for implementation.material. Occidental Chemical Corporation, one of the PRPs, has committed to performcommenced the remedial design required by the ROD Remedy, reserving its right of cost contribution from all other PRPs.
In September 2017, the EPA concluded that an Agency-commenced allocation process for the Passaic River’s lower 8.3 miles should include only certain PRPs. The allocation is intended to lead to a consent decree in which certain of the PRPs agree to perform the remedial action under EPA oversight. Discussions on the matter are ongoing. Conversations between the EPA and the PRPs regarding remediation of the Passaic River’s upper 9 miles are ongoing.
Based upon (i) the estimated cost of the ROD Remedy, (ii) PSEG’s estimatebut declined to participate in the allocation process. Instead, it filed suit against PSE&G and others seeking cost recovery and contribution under CERCLA but has not quantified alleged damages. The litigation is ongoing and PSEG cannot predict the outcome.
Two PRPs, Tierra Solutions, Inc. (Tierra) and Maxus Energy Corporation (Maxus), have filed for Chapter 11 bankruptcy. The trust representing the creditors in this proceeding has filed a complaint asserting claims against Tierra’s and Maxus’ current and former parent entities, among others. Any damages awarded may be used to fund the remediation of the LPRSA.
As of December 31, 2020, PSEG has approximately $65 million accrued for this matter. PSE&G’s&G has an Environmental Costs Liability of $52 million and Power’s shares of that cost, and (iii) thea corresponding Regulatory Asset based on its continued ability of PSE&G to recover such costs in its rates, as of December 31, 2017,rates. PSEG has accrued approximately $57 million. Of this amount $46 million has been accrued by PSE&G as an Environmental Costs Liability and a corresponding Regulatory Asset and $11 million has been accrued by Power ashas an Other Noncurrent Liability with the corresponding O&M Expense recorded in the periods when the liability was accrued.of $13 million.
The EPA has broad authority to implement its selectedoutcome of this matter is uncertain, and until (i) a final remedy through the ROD and PSEG cannot at this time predict how the implementation of the ROD might impact PSE&G’s and Power’s ultimate liability. Until (i) the RI/FS, which coversfor the entire 17 miles of the lower Passaic River,LPRSA is finalized either in whole or in part, (ii)selected and an agreement is reached by the PRPs to perform either the ROD Remedy as issued, or an amended ROD Remedy determined through negotiation or litigation, and an agreed upon remedy for the remaining 8.7 miles of the river, are reached, (iii)fund it, (ii) PSE&G’s and PSEG Power’s respective shares of the costs both in the aggregate as well as individually, are determined, and (iv)(iii) PSE&G’s continued ability to recover the costs in its rates is determined, it is not possible to predict this matter’s ultimate impact on PSEG’s financial statements. It is possible that PSE&G and PSEG Power will record additional costs beyond what they have accrued, and that such costs could be material, but PSEG cannot at the current time estimate the amount or range of any additional costs.
Natural Resource Damage Claims
In 2003, the New Jersey Department of Environmental Protection (NJDEP) directedand certain federal regulators have alleged that PSE&G, PSEG PSE&GPower and 56 other PRPs to arrangemay be liable for a natural resource damage assessment and interim compensatory restoration of natural resource injuries alongdamages within the lower Passaic River and its tributaries pursuant to the New Jersey Spill Compensation and Control Act. The NJDEP alleged that hazardous substances had been discharged from the Essex Site and the Harrison Site. The NJDEP estimated the cost of interim natural resource injury restoration activities along the lower Passaic River at approximately $950 million.LPRSA. In 2007, agencies of the U.S. Department of Commerce and the U.S. Department of the Interior (the Passaic River federal trustees) sent letters toparticular, PSE&G, PSEG Power and other PRPs inviting participation in an assessmentreceived notice from federal regulators of injuriesthe regulators’ intent to move forward with a series of studies assessing potential damages to natural resources thatat the agencies intended to perform. In 2008, PSEGDiamond Alkali Superfund Site, which includes the LPRSA and a number of other PRPs agreed to share certain immaterial costs the trustees have incurred and will incur going forward, and to work with the trustees to explore whether some or all of the trustees’ claims can be resolved in a cooperative fashion. That effort is continuing.Newark Bay Study Area. PSE&G and PSEG Power are unable to estimate their respective portions of theany possible loss or range of loss related to this matter.
Newark Bay Study Area
The EPA has established the Newark Bay Study Area, which it defines asis an extension of the LPRSA and includes Newark Bay and portions of the Hackensack River, the Arthur Kill and the Kill Van Kull. In August 2006, thesurrounding waterways. The EPA senthas notified PSEG and 11 other entities notices that it considered eachPRPs of the entities to be a PRP with respect to contamination in the Study Area. The notice letter requested that the PRPs fund an EPA-approved study in the Newark Bay Study Area. The notice stated the EPA’s belief that hazardous substances were released from sites owned by PSEG companies and located on the Hackensack River, including two operating electric generating

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stations (Hudson and Kearny sites) and one former MGP site. PSEG has participated in and partially funded the second phase of this study. Notices to fund the next phase of the study have been received but PSEG has not consented to fund the third phase.their potential liability. PSE&G and PSEG Power are unable to estimate their respective portions of the possibleany loss or possible range of loss related to this matter. In December 2018, PSEG Power completed the sale of the site of the Hudson electric generating station. PSEG Power contractually transferred all land rights and structures on the Hudson site to a third-party purchaser, along with the assumption of the environmental liabilities for the site.
MGP Remediation Program
PSE&G is working with the NJDEPNew Jersey Department of Environmental Protection (NJDEP) to assess, investigate and remediate environmental conditions at its former MGP sites. To date, 38 sites requiring some level of remedial action have been identified. Based on its current studies, PSE&G has determined that the estimated cost to remediate all MGP sites to completion could range between $358$320 million and $403$358 million on an undiscounted basis, through 2021, including its $46$52 million share for the Passaic River as discussed above. Since no amount within the range is considered to be most likely, PSE&G has recorded a liability of $358$320 million as ofDecember 31, 2017.2020. Of this amount, $79$89 million was recorded in Other Current Liabilities and $279$231 million was reflected as Environmental Costs in Noncurrent Liabilities. PSE&G has recorded a $358$320 millionRegulatory Asset with respect to these costs. PSE&G periodically updates its studies taking into account any new regulations or new information which could impact future remediation costs and adjusts its recorded liability accordingly. NJDEP, PSEG and EPA representatives have had discussions regarding to what extentPSE&G completed sampling in the Passaic River is required to delineate coal tar from certain MGP sites that abut the Passaic River Superfund site. PSEG cannot determine at this time whether this will have an impact on the Passaic River Superfund remedy.
Clean Water Act (CWA) Permit RenewalsCWA Section 316(b) Rule
Pursuant toThe EPA’s CWA Section 316(b) rule establishes requirements for the Federal Water Pollution Control Act (FWPCA),regulation of cooling water intakes at existing power plants and industrial facilities with a design flow of more than two million gallons of water per day. The EPA requires that National Pollutant Discharge Elimination System permits expire withinbe renewed every five years and that each state Permitting Director
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Table of their effective date. In order to renew theseContents

manage renewal permits but allowfor its respective power generation facilities on a plant to continue to operate, an owner or operator must file a permit application no later than six months prior to expiration of the permit. States with delegated federal authority for this program manage these permits.case by case basis. The NJDEP manages the permits under the New Jersey Pollutant Discharge Elimination System (NJPDES) program. Connecticut and New York also have permits to manage their respective pollutant discharge elimination system programs.
In May 2014, the EPA issued a final cooling water intake rule that 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 has structured the rule so that each state Permitting Director will continue to consider renewal permits for existing
power facilities on a case by case basis, based on studies related to impingement mortality and entrainment and submit the results with their permit applications to be conducted by the facilities seeking renewal permits.
Several environmental organizations and certain energy industry groups have filed suit under the Clean Water Act and the Endangered Species Act. The cases have been consolidated at the Second Circuit and a decision remains pending.
In June 2016, the NJDEP issued a final NJPDES permit for Salem. The final permit does not mandate specific service water system modifications, but consistent with Section 316 (b) of the CWA, it requires additional studies and the selection of technology to address impingement for the service water system. The final permit does not mandate specific service water system modifications but, it requires additional studies and the selection of technology to address impingement for the service water system. In July 2016, the Delaware Riverkeeper Network (Riverkeeper) filed aan administrative hearing request challenging certain conditions of the permit, including the NJDEP’s issuanceapplication of the final NJPDES renewal permit for Salem. NJDEP has granted the hearing request, but it has not yet been scheduled. The Riverkeeper’s filing does not change the effective date of the permit.316(b) rule. If the Riverkeeper’s challenge wereis successful, PSEG Power may be required to incur additional costs to comply with the CWA. Potential cooling water and/or service water system modification costs could be material and could adversely impact the economic competitiveness of this facility.
State permitting decisions at Bridgeport and possibly New Haven could also have a material impact on Power’s ability to renew permits at its existing larger once-through cooled plants without making significant upgrades to existing intakes and cooling systems.
Power is unable to predict The NJDEP had granted the outcome of these permitting decisions and the effect, if any, that they may have on Power’s future capital requirements, financial condition or results of operations.
Power is actively engaged with the Connecticut Department of Energy and Environmental Protection (CTDEEP) regarding renewal of the current permit for the cooling water intake structure at Bridgeport Harbor Station Unit 3 (BH3). To address compliance with the EPA’s CWA Section 316(b) final rule, Powerhearing request but no hearing date has proposed to continue to operate BH3 without making the capital expenditures for modification to the existing intake structure and retire BH3 in 2021, which is four years earlier than the previously estimated useful life ending in 2025. Power is currently awaiting action by the CTDEEP to issue a draft and then a final permit.
Power has negotiated a Community Environmental Benefit Agreement (CEBA) with the City of Bridgeport, Connecticut and local community organizations. That CEBA provides that Power would retire BH3 early if all of its conditions precedent occur, which include receipt of all final permits to build and operate a proposed new combined cycle generating facility on the same

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site that BH3 currently operates. Absent those conditions being met, and the permit for the cooling water intake structure referred to above not being issued, Power may seek to operate BH3 through the previously estimated useful life.
In February 2016, the proposed new generating facility at Bridgeport Harbor was awarded a capacity obligation. The Connecticut Siting Council (CSC) issued an order to approve siting Bridgeport Harbor Station unit 5 (BH5). All major environmental permits have been received; however, secondary approvals are still being obtained to allow operations to begin in mid-2019. Power’s obligations under the CEBA are being monitored regularly and carried out as needed.
Bridgeport Harbor National Pollutant Discharge Elimination System (NPDES) Permit Compliance
In April 2015, Power determined that monitoring and reporting practices related to certain permitted wastewater discharges at its Bridgeport Harbor station may have violated conditions of the station’s NPDES permit and applicable regulations and could subject it to fines and penalties. Power has notified the CTDEEP of the issues and has taken actions to investigate and resolve the potential non-compliance. Power cannot predict the impact of this matter.established.
Jersey City, New Jersey Subsurface Feeder Cable Matter
In early October 2016, a discharge of dielectric fluid from subsurface feeder cables located in the Hudson River near Jersey City, New Jersey, was identified and reported to the NJDEP. The feeder cables are located within a subsurface easement granted to PSE&G by the property owners, Newport Associates Development Company (NADC) and Newport Associates Phase I Developer Limited Partnership. The feeder cables are subject to agreements between PSE&G and Consolidated Edison Company of New York, Inc. (Con Edison) and are jointly owned by PSE&G and Con Edison, with PSE&G owning the portion of the cables located in New Jersey and Con Edison owning the portion of the cables located in New York. The NJDEP has declared an emergency and an emergency response action has been undertaken to investigate, contain, remediate and stop the fluid discharge; to assess, repair and restore the cables to good working order, if feasible; and to restore the property. The regulatory agencies overseeing the emergency response, including the U.S. Coast Guard, the NJDEP and the Army Corps of Engineers, have issued multiple notices, orders and directives to the various parties related to this matter.Edison. The impacted cable was repaired in late-September 2017; however,September 2017. A federal response was initially led by the U.S. Coast Guard. The U.S. Coast Guard transitioned control of the federal response to the EPA, and the EPA ended the federal response to the matter in 2018. The investigation of small amounts of residual dielectric fluid continuesbelieved to appear onbe contained with the surface and so the investigation and response actions related to the fluid discharge are ongoing. PSE&G may determine that retirementmarina sediment is ongoing as part of the affected facilities would be appropriate. Also ongoingNJDEP site remediation program. In August 2020, PSE&G finalized a settlement with the federal government regarding the reimbursement of costs associated with the federal response to this matter and payment of civil penalties of an immaterial amount.
A lawsuit in federal court is the processpending to determine ultimate responsibility for the costs to address the leak among PSE&G, Con Edison and NADC, including an action filed by PSE&G in New Jersey federal court seeking damages from NADC. In that action, NADC has also pursued counterclaimsaddition, Con Edison filed counter claims against PSE&G and Con EdisonNADC, including seeking damages for its costs to address the leak. In addition, NADC provided notice to the New Jersey Secretary of Transportation of several alleged violations by Con Edison and PSE&G of regulations prescribed under the Hazardous Liquids Pipeline Safety Act (HLPSA), a requirement to preserve NADC’s right to pursue injunctive relief under the HLPSA.and damages. Based on the information currently available and depending on the outcome of the New Jersey federal court action, PSE&G’s portion of the costs to address the leak may be material; however, PSE&G anticipates that it will recover theseits costs, other than civil penalties, through regulatory proceedings.
Steam Electric Effluent GuidelinesBGS, BGSS and ZECs
In September 2015, the EPA issued a new Effluent Limitation Guidelines Rule (ELG Rule) for steam electric generating units. The rule establishes new best available technology economically achievable (BAT) standards for fly ash transport water, bottom ash transport water, flue gas desulfurization and flue gas mercury control wastewater. Power’s Bridgeport Harbor station and the jointly-owned Keystone and Conemaugh stations, have bottom ash transport water discharges that are regulated under the ELG Rule. Keystone and Conemaugh also have flue gas desulfurization wastewaters regulated by the ELG Rule.
Through various orders, the EPA has stayed the compliance dates in the ELG Rule and has announced plans to further revise the requirements and compliance dates of the ELG Rule. Power is unable to determine how this will ultimately impact its compliance requirements or its financial condition and results of operations.
Basic Generation Service (BGS) and Basic Gas Supply Service (BGSS)
Each year, PSE&G obtains its electric supply requirements through the annual New Jersey BGS auctions for two categories of customers whothat choose not to purchase electric supply from third-party suppliers. The first category, which represents about 80% of PSE&G’s load requirement, is residential and smaller commercial and industrial customers (BGS-Residential Small Commercial Pricing (RSCP)). The second category is larger customers that exceed a BPU-established load (kW) threshold (BGS-Commercial and Industrial Energy Pricing (CIEP)). Pursuant to applicable BPU rules, PSE&G enters into the Supplier Master AgreementAgreements with the winners of these RSCP and CIEP BGS auctions following the BPU’s approval of the auction results. PSE&G has entered into contracts with winning BGS suppliers, including Power, to purchase BGS for PSE&G’s load requirements. The winners of the auction (including Power) areRSCP and CIEP auctions have been responsible for fulfilling all the requirements of a PJM Load Serving Entityload-serving entity including the provision of capacity, energy, ancillary services, transmission and any other services required by PJM. BGS suppliers assume all volume risk and customer migration risk and must satisfy New Jersey’s renewable portfolio standards. Beginning with the 2021 BGS auction, transmission will become the responsibility of the New Jersey EDCs, and will no longer be a component of the BGS auction product for either the RSCP or CIEP auctions. BGS suppliers serving load from the 2018, 2019 and 2020 BGS auctions have the option to transfer the transmission obligation to the New Jersey EDCs as of February 2021. Suppliers that do so will have their total BGS payment from the EDCs reduced to reflect the transfer of the transmission obligation to the EDCs.
The BGS-CIEP auction is for a one-year supply period from June 1 to May 31 with the BGS-CIEP auction price measured in dollars per MW-day for capacity. The final price for the BGS-CIEP auction year commencing June 1, 20182021 is $287.76$351.06 per MW-

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day,MW-day, replacing the BGS-CIEP auction year price ending May 31, 20182021 of $276.83$359.98 per MW-day. Energy for BGS-CIEP is priced at hourly PJM locational marginal prices for the contract period.
PSE&G contracts for its anticipated BGS-RSCP load on a three-year rolling basis, whereby each year one-third of the load is procured for a three-year period. The contract prices in dollars per MWh for the BGS-RSCP supply, as well as the approximate load, are as follows:
 Auction Year 
 2018201920202021 
36-Month Terms EndingMay 2021May 2022May 2023May 2024(A) 
Load (MW)2,900 2,800 2,800 2,900 
$ per MWh$91.77$98.04$102.16$64.80
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  Auction Year  
  2015 2016 2017 2018  
 36-Month Terms EndingMay 2018
 May 2019
 May 2020
 May 2021
(A)  
 Load (MW)2,900
 2,800
 2,800
 2,900
   
 $ per MWh$99.54 $96.38 $90.78 $91.77   
           
(A)(A)Prices set in the 2018 BGS auction will become effective on June 1, 2018 when the 2015 BGS auction agreements expire.
Power seeks to mitigate volatility in its results by contracting in advance for the sale of most of its anticipated electric output as well as its anticipated fuel needs. As part of its objective, Power has entered into contracts to directly supply PSE&G and other New Jersey electric distribution companies (EDCs) with a portion of their respective BGS requirements through the New Jersey2021 BGS auction process, described above.will become effective on June 1, 2021 when the 2018 BGS auction agreements expire.
PSE&G has a full-requirements contract with PSEG Power to meet the gas supply requirements of PSE&G’s gas customers. PSEG Power has entered into hedges for a portion of these anticipated BGSS obligations, as permitted by the BPU. The BPU permits PSE&G to recover the cost of gas hedging up to 115 billion cubic feet or 80% of its residential gas supply annual requirements through the BGSS tariff. Current plans call for PSEG Power to hedge on behalf of PSE&G approximately 70 billion cubic feet or 50% of its residential gas supply annual requirements. For additional information, see Note 24.26. Related-Party Transactions.
Pursuant to a process established by the BPU, New Jersey EDCs, including PSE&G, are required to purchase ZECs from eligible nuclear plants selected by the BPU. In April 2019, PSEG Power’s Salem 1, Salem 2 and Hope Creek nuclear plants were selected to receive ZEC revenue for approximately three years, through May 2022. PSE&G has implemented a tariff to collect a non-bypassable distribution charge in the amount of $0.004 per KWh from its retail distribution customers to be used to purchase the ZECs from these plants. PSE&G will purchase the ZECs on a monthly basis with payment to be made annually following completion of each energy year. The legislation also requires nuclear plants to reapply for any subsequent three-year periods and allows the BPU to adjust prospective ZEC payments.
Minimum Fuel Purchase Requirements
PSEG Power’s nuclear fuel strategy is to maintain certain levels of uranium and to make periodic purchases to support such levels. As such, the commitments referred to in the following table may include estimated quantities to be purchased that deviate from contractual nominal quantities. PSEG Power’s nuclear fuel commitments cover approximately 100% of its estimated uranium, enrichment and fabrication requirements through 20202021 and a significant portion through 2022 at Salem, Hope Creek and Peach Bottom.
PSEG Power has various multi-year contracts for natural gas and firm transportation and storage capacity for natural gas that are primarily used to meet its obligations to PSE&G. When there is excess delivery capacity available beyond the needs of PSE&G’s customers, PSEG Power can use the gas to supply its fossil generating stations.
Power also has various long-term fuel purchase commitments for coal through 2021 to support its fossil generation stations.stations in New Jersey.
As of December 31, 2017,2020, the total minimum purchase requirements included in these commitments were as follows:
Fuel TypePSEG Power’s Share of Commitments through 2025
Millions
Nuclear Fuel
Uranium$193 
Enrichment$346 
Fabrication$174 
Natural Gas$1,256 
     
 Fuel Type Power's Share of Commitments through 2022 
   Millions 
 Nuclear Fuel   
 Uranium $240
 
 Enrichment $391
 
 Fabrication $170
 
 Natural Gas $1,042
 
 Coal $293
 
     
Pending FERC Matters

PSE&G has received requests for information and a Notice of Investigation from FERC’s Office of Enforcement concerning a transmission project. PSE&G retained outside counsel to assist with an internal investigation. PSE&G is fully cooperating with FERC’s requests for information and the investigation. It is not possible at this time to predict the outcome of this matter.
Pending Tropical Storm Matter
Following the effects of Tropical Storm Isaias, the New York Attorney General 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 state electric service providers, including PSEG LI, and other state telephone, cable and internet providers into their preparation and restoration efforts following Tropical Storm Isaias.Although the inquiry by the New York Attorney General remains pending, the DPS issued an interim storm investigation report. With respect to PSEG LI, the DPS’ report found that PSEG LI violated its Emergency Response Plan and DPS Regulations, and recommended that LIPA consider taking various actions, including terminating or renegotiating the Amended and Restated OSA. LIPA also initiated its own review of PSEG LI’s performance and issued a report with recommendations for improvements to PSEG LI’s structure and processes, including a timeline for implementing those recommendations. That report also recommended that LIPA either renegotiate or terminate the OSA.
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Regulatory Proceedings
FERC Compliance
PJM Bidding MatterPSEG LI agreed with LIPA that it would fund approximately $6.5 million in claims by customers for food and medication spoilage costs incurred as a result of being without electric service during the storm.
In December 2020, LIPA filed a complaint against PSEG LI in New York State court alleging multiple breaches of the first quarterOSA in connection with PSEG LI’s preparation for and response to Tropical Storm Isaias seeking specific performance and $70 million in damages. Pursuant to recommendations by the New York State Department of 2014, Power discovered that it incorrectly calculated certain componentsPublic Service, LIPA has initiated a series of actions to allow its cost-based bids forboard to determine whether to seek to terminate the OSA or instead continue with PSEG LI as its Service Provider.
PSEG LI is fully cooperating with the inquiries by the New Jersey fossil generating unitsYork Attorney General and the DPS, and we cannot predict their outcome. PSEG LI also continues to work closely with LIPA to address the recommendations in LIPA’s report. PSEG LI intends to vigorously defend itself with regard to the allegations in LIPA’s complaint alleging breaches of the OSA; however a decision in this proceeding requiring specific performance or the payment of damages by PSEG LI or resulting in the PJM energy market. Upon discoverytermination of the errors,OSA could have a material adverse effect on PSEG’s results of operations and financial condition.
Pending BPU Audit of PSE&G
In September 2020, the BPU ordered the commencement of a comprehensive affiliate and management audit of PSE&G. Phase 1 of the planned audit will review affiliate relations and cost allocation between PSE&G and its affiliates, including an analysis of the relationship between PSE&G and PSEG retained outside counselEnergy Resources & Trade, LLC, a wholly owned subsidiary of PSEG Power over the past ten years, and between PSE&G and PSEG LI. Phase 2 will be a comprehensive management audit, which will address, among other things, executive management, corporate governance, system operations, human resources, cyber security, compliance with customer protection requirements and customer safety. It is not possible at this time to assist inpredict the conductoutcome of an investigation into the matter and self-reported the errors. As the internal investigation proceeded, additional pricing errors in the bids were identified. It was further determined that the quantity of energy that Power offered into the energy market for its fossil peaking units differed from the amount for which Power was compensated in the capacity market for those units. PSEG informed FERC, PJM and the PJM Independent Market Monitor (IMM) of these additional issues, corrected the identified errors, and modified the bid quantities for Power’s peaking units. Power has implemented procedures and continues to review its policies and practices to mitigate the risk of similar issues occurring in the future. During the three month period ended March 31, 2014, based upon its best estimate available at the time, Power recorded a pre-tax charge to income in the amount of $25 million related to this matter.
Since September 2014, FERC Staff has been conductingLitigation
Sewaren 7 Construction
In June 2018, a preliminary, non-public staff investigation into these matters. While considerable uncertainty remains ascomplaint was filed in federal court in Newark, New Jersey against PSEG Fossil LLC, a wholly owned subsidiary of PSEG Power, regarding an ongoing dispute with Durr Mechanical Construction, Inc. (Durr), a contractor on the Sewaren 7 project. Among other things, Durr seeks damages of $93 million and alleges that PSEG Power withheld money owed to Durr and that PSEG Power’s intentional conduct led to the final resolutioninability of Durr to obtain prospective contracts. PSEG Power intends to vigorously defend against these matters, based upon developmentsallegations. In January 2021, the court partially granted PSEG Power’s motion to dismiss certain claims, reducing the amount claimed to $68 million. In December 2018, Durr filed for Chapter 11 bankruptcy in the investigationfederal court in the first quarterSouthern District of 2017, Power believesNew York (SDNY). The SDNY bankruptcy court has allowed the disgorgement and interest costs relatedNew Jersey litigation to the cost-based bidding matter may range between approximately $35 million and $135 million, depending on the legal interpretation of the principles under the PJM Tariff, plus penalties. Since no point within this range is more likely than any other,proceed. PSEG Power has accrued the low endan amount related to outstanding invoices which does not reflect an assessment of claims and potential counterclaims in this range of $35 million by recording an additional pre-tax chargematter. Due to income of $10 million during the three months ended March 31, 2017. Power is unable to reasonably estimate the range of possible loss, if any, for the quantity of energy offered matter or the penalties that FERC would impose relating to either the cost-based bidding or quantity of energy matter. However, any of these amounts could be individually material toits preliminary nature, PSEG and Power.
Power continues to believe that it has legal defenses that it may assert in a judicial challenge, including the legal defense that its cost-based bidding in a substantial majority of the hours was below the allowed rate under the Tariff and therefore any errors in those hours did not violate the Tariff or were immaterial. Furthermore, it is unclear whether the quantity of energy offered violated any legal requirement. As a result, PSEG and Power cannot predict the final outcome of these matters.this matter.
Other Litigation and Legal Proceedings
PSEG and its subsidiaries are party to various lawsuits in the ordinary course of business. In view of the inherent difficulty in predicting the outcome of such matters, PSEG, PSE&G and PSEG Power generally cannot predict the eventual outcome of the pending matters, the timing of the ultimate resolution of these matters, or the eventual loss, fines or penalties related to each pending matter.
In accordance with applicable accounting guidance, a liability is accrued when those matters present loss contingencies that are both probable and reasonably estimable. In such cases, there may be an exposure to loss in excess of any amounts accrued. PSEG will continue to monitor the matter for further developments that could affect the amount of the accrued liability that has been previously established.
Based on current knowledge, management does not believe that loss contingencies arising from pending matters, other than the matters described herein, could have a material adverse effect on PSEG’s, PSE&G’s or PSEG Power’s consolidated financial position or liquidity. However, in light of the inherent uncertainties involved in these matters, some of which are beyond PSEG’s control, and the large or indeterminate damages sought in some of these matters, an adverse outcome in one or more of these matters could be material to PSEG’s, PSE&G’s or PSEG Power’s results of operations or liquidity for any particular reporting period.
Ongoing Coronavirus Pandemic
PSE&G, PSEG Power and PSEG LI are providing essential services during this national emergency related to the ongoing coronavirus (COVID-19) pandemic. The ongoing coronavirus pandemic has not had a material impact on our results of operations, financial condition or cash flows for the year ended December 31, 2020. However, the potential future impact of the pandemic and the associated economic impacts, which could extend beyond the duration of the pandemic, could have risks that
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drive certain accounting considerations. The ultimate impact of the ongoing coronavirus pandemic is highly uncertain and cannot be predicted at this time.
Nuclear Insurance Coverages and Assessments
PSEG Power is a member of the joint underwriting association, American Nuclear Insurers (ANI), which provides nuclear liability insurance coverage at the Salem and Hope Creek site and the Peach Bottom site. The ANI policies are designed to satisfy the financial protection requirements outlined in the Price-Anderson Act, which sets the limit of liability for claims that could arise from an incident involving any licensed nuclear facility in the United States. The limit of liability per incident per site is composed of primary and excess layers. As of December 31, 2017,2020, nuclear sites were required to purchase $450 million of primary liability coverage for each site (through ANI). The primary layer is supplemented by an excess layer, which is an industry self-insurance pool. In the event a nuclear site, which is part of the industry self-insurance pool, has a claim that exceeds the primary layer, each licensee would be assessed a prorated share of the excess layer. The excess layer limit is $13.4$13.3 billion. PSEG Power’s maximum aggregate assessment per incident is $401$433 million (based on PSEG Power’s ownership interests in Salem, Hope Creek and Peach Bottom) and its maximum aggregate annual assessment per incident is $60$65 million. If the damages exceed the limit of liability, Congress could impose further revenue-raising measures on the nuclear industry to pay claims. Further, a decision by the U.S. Supreme Court, not involving PSEG Power, held that the Price-Anderson Act did not preclude punitive damage awards based on state law claims.

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PSEG Power is also a member of an industry mutual insurance company, Nuclear Electric Insurance Limited (NEIL), which provides the property, decontamination and decommissioning liability insurance at the Salem and Hope Creek site and the Peach Bottom site. NEIL also provides replacement power coverage through its accidental outage policy. NEIL policies may make retrospective premium assessments in the case of adverse loss experience. The current maximum aggregate annual retrospective premium obligation for PSEG Power is approximately $76$49 million. NEIL requires its members to maintain an investment grade credit rating or to ensure collectability of their annual retrospective premium obligation by providing a financial guarantee, letter of credit, deposit premium, or some other means of assurance. Certain provisions in the NEIL policies provide that the insurer may suspend coverage with respect to all nuclear units on a site without notice if the NRC suspends or revokes the operating license for any unit on that site, issues a shutdown order with respect to such unit or issues a confirmatory order keeping such unit down.
The ANI and NEIL policies all include coverage for claims arising out of acts of terrorism. However, NEIL policies are subject to an industry aggregate limit of $3.2 billion plus such additional amounts as NEIL recovers for such losses from reinsurance, indemnity and any other source applicable to such losses.
Minimum Lease Payments
142

The total future minimum payments under various operating leases asNOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Table of December 31, 2017 are:Contents

             
   PSE&G Power Services Other Total 
   Millions   
 2018 $16
 $5
 $14
 $1
 $36
 
 2019 9
 6
 15
 1
 31
 
 2020 8
 3
 15
 1
 27
 
 2021 8
 3
 15
 1
 27
 
 2022 7
 3
 15
 1
 26
 
 Thereafter 65
 38
 120
 1
 224
 
 Total Minimum Lease Payments $113
 $58
 $194
 $6
 $371
 
             

Note 14.16. Debt and Credit Facilities
Long-Term Debt
As of December 31,
 Maturity20202019
 Millions
PSEG
Term Loan:
Variable Rate2020$0 $700 
Total Term Loan0 700 
Senior Notes:
2.00%2021300 300 
2.65%2022700 700 
2.88%2024750 750 
0.80%2025550 0 
1.60%2030550 0 
8.63%(A)203196 0 
Total Senior Notes2,946 1,750 
Principal Amount Outstanding2,946 2,450 
Amounts Due Within One Year(300)(700)
Net Unamortized Discount and Debt Issuance Costs(17)(9)
Total Long-Term Debt of PSEG$2,629 $1,741 
         
     As of December 31, 
   Maturity 2017 2016 
     Millions 
 PSEG       
 Term Loan:       
 Variable 2017 $—
 $500
 
 Variable 2019 700
 —
 
 Total Term Loan   700
 500
 
 Senior Notes:       
 1.60% 2019 400
 400
 
 2.00% 2021 300
 300
 
 2.65% 2022 700
 —
 
 Total Senior Notes   1,400
 700
 
 Principal Amount Outstanding   2,100
 1,200
 
 Amounts Due Within One Year   —
 (500) 
 Net Unamortized Discount and Debt Issuance Costs   (9) (5) 
 Total Long-Term Debt of PSEG   $2,091
 $695
 
         




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`

         
     As of December 31, 
   Maturity 2017 2016 
     Millions 
 PSE&G       
 First and Refunding Mortgage Bonds (A):       
 9.25% 2021 $134
 $134
 
 8.00% 2037 7
 7
 
 5.00% 2037 8
 8
 
 Total First and Refunding Mortgage Bonds   149
 149
 
 Medium-Term Notes (MTNs) (A):       
 5.30% 2018 400
 400
 
 2.30% 2018 350
 350
 
 1.80% 2019 250
 250
 
 2.00% 2019 250
 250
 
 7.04% 2020 9
 9
 
 3.50% 2020 250
 250
 
 1.90% 2021 300
 300
 
 2.38% 2023 500
 500
 
 3.75% 2024 250
 250
 
 3.15% 2024 250
 250
 
 3.05% 2024 250
 250
 
 3.00% 2025 350
 350
 
 2.25% 2026 425
 425
 
 3.00% 2027 425
 —
 
 5.25% 2035 250
 250
 
 5.70% 2036 250
 250
 
 5.80% 2037 350
 350
 
 5.38% 2039 250
 250
 
 5.50% 2040 300
 300
 
 3.95% 2042 450
 450
 
 3.65% 2042 350
 350
 
 3.80% 2043 400
 400
 
 4.00% 2044 250
 250
 
 4.05% 2045 250
 250
 
 4.15% 2045 250
 250
 
 3.80% 2046 550
 550
 
 3.60% 2047 350
 —
 
 Total MTNs   8,509
 7,734
 
 Principal Amount Outstanding   8,658
 7,883
 
 Amounts Due Within One Year   (750) —
 
 Net Unamortized Discount and Debt Issuance Costs   (67) (65) 
 Total Long-Term Debt of PSE&G   $7,841
 $7,818
 
         


  As of December 31,
 Maturity20202019
  Millions
PSE&G
First and Refunding Mortgage Bonds (B):
9.25%2021$134 $134 
8.00%20377 7 
5.00%20378 8 
Total First and Refunding Mortgage Bonds149 149 
Medium-Term Notes (B):
3.50%20200 250 
7.04%20200 9 
1.90%2021300 300 
2.38%2023500 500 
3.25%2023325 325 
3.75%2024250 250 
3.15%2024250 250 
3.05%2024250 250 
3.00%2025350 350 
2.25%2026425 425 
3.00%2027425 425 
3.70%2028375 375 
3.65%2028325 325 
3.20%2029375 375 
2.45%2030300 0 
5.25%2035250 250 
5.70%2036250 250 
5.80%2037350 350 
5.38%2039250 250 
5.50%2040300 300 
3.95%2042450 450 
3.65%2042350 350 
3.80%2043400 400 
4.00%2044250 250 
4.05%2045250 250 
4.15%2045250 250 
3.80%2046550 550 
3.60%2047350 350 
4.05%2048325 325 
3.85%2049375 375 
3.20%2049400 400 
3.15%2050300 0 
2.70%2050375 0 
2.05%2050375 0 
Total MTNs10,850 9,759 
Principal Amount Outstanding10,999 9,908 
Amounts Due Within One Year(434)(259)
Net Unamortized Discount and Selling Expense(90)(81)
Total Long-Term Debt of PSE&G$10,475 $9,568 
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     As of December 31, 
   Maturity 2017 2016 
     Millions 
 Power       
 Senior Notes:       
 2.45% 2018 $250
 $250
 
 5.13% 2020 406
 406
 
 4.15% 2021 250
 250
 
 3.00% 2021 700
 700
 
 4.30% 2023 250
 250
 
 8.63% 2031 500
 500
 
 Total Senior Notes   2,356
 2,356
 
 Pollution Control Notes:       
 Floating Rate (B) 2019 44
 44
 
 Total Pollution Control Notes   44
 44
 
 Principal Amount Outstanding   2,400
 2,400
 
 Amounts Due Within One Year   (250) —
 
 Net Unamortized Discount and Debt Issuance Costs   (14) (18) 
 Total Long-Term Debt of Power   $2,136
 $2,382
 
         
 As of December 31,
 Maturity20202019
  Millions
PSEG Power
Senior Notes:
5.13%2020$0 $406 
3.00%2021700 700 
4.15%2021250 250 
3.85%2023700 700 
4.30%2023250 250 
8.63%(A)2031404 500 
Total Senior Notes2,304 2,806 
Pollution Control Notes:
Floating Rate (C)202244 44 
Total Pollution Control Notes44 44 
Principal Amount Outstanding2,348 2,850 
Amounts Due Within One Year(950)(406)
Net Unamortized Discount and Debt Issuance Costs(6)(10)
Total Long-Term Debt of PSEG Power$1,392 $2,434 
(A)Secured by essentially all property of PSE&G pursuant to its First and Refunding Mortgage.
(B)The Pennsylvania Economic Development Authority (PEDFA) bond that is serviced and secured by Power Pollution Control Notes, is a variable rate bond that is in weekly reset mode.
(A)In December 2020, PSEG issued $96 million principal amount of 8.63% Senior Notes due 2031 to holders of a like principal amount of 8.63% Senior Notes due 2031 originally issued by PSEG Power who validly tendered their notes pursuant to an offer to exchange. Upon consummation of the offer to exchange, the PSEG Power notes accepted in the exchange were cancelled. The transaction resulted in a non-cash financing activity for both PSEG and PSEG Power.
(B)Secured by essentially all property of PSE&G pursuant to its First and Refunding Mortgage.
(C)The Pennsylvania Economic Development Financing Authority (PEDFA) bond that is serviced and secured by PSEG Power Pollution Control Notes is a variable rate bond that is in weekly reset mode.
Long-Term Debt Maturities
The aggregate principal amounts of maturities for each of the five years following December 31, 20172020 are as follows:
           
 Year PSEG PSE&G Power Total 
     
 2018 $—
 $750
 $250
 $1,000
 
 2019 1,100
 500
 44
 1,644
 
 2020 —
 259
 406
 665
 
 2021 300
 434
 950
 1,684
 
 2022 700
 —
 —
 700
 
 Thereafter —
 6,715
 750
 7,465
 
 Total $2,100
 $8,658
 $2,400
 $13,158
 
           
YearPSEGPSE&GPSEG PowerTotal
 
2021$300 $434 $950 $1,684 
2022700 0 44 744 
20230 825 950 1,775 
2024750 750 0 1,500 
2025550 350 0 900 
Thereafter646 8,640 404 9,690 
Total$2,946 $10,999 $2,348 $16,293 
Long-Term Debt Financing Transactions
During 2017,2020, PSEG and its subsidiaries had the following Long-Term Debt issuances, maturities and redemptions:
PSEG
entered into an agreement for a new term loan maturing June 2019. The term loan has a balance of $700 million at an interest rate of 1 month LIBOR + 0.80% and can be terminated at any time without penalty,
•issued $700$550 million of 2.65%0.80% Senior Notes due November 2022, andAugust 2025,
redeemed at maturity a $500•issued $550 million term loan at an interest rate of 1 month LIBOR + 0.875%1.60% Senior Notes due November 2017.


August 2030,
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•issued $96 million of 8.63% Senior Notes due April 2031 in exchange for a like amount of 8.63% Senior Notes due April 2031 originally issued by PSEG Power, and
•retired a $700 million Term Loan at maturity.
PSE&G
•issued $425$300 million of 3.00%2.45% Secured Medium-Term Notes, Series LN, due May 2027, andJanuary 2030,
•issued $350$300 million of 3.60%3.15% Secured Medium-Term Notes, Series LN, due December 2047.January 2050,
•issued $375 million of 2.70% Secured Medium-Term Notes, Series N, due May 2050,
•issued $375 million of 2.05% Secured Medium-Term Notes, Series N, due August 2050,
•retired $250 million of 3.50% Medium-Term Notes, Series G, at maturity, and
•retired $9 million of 7.04% Medium-Term Notes, Series A, at maturity.
PSEG Power
•retired $406 million of 5.13% Senior Notes at maturity, and
•cancelled $96 million of 8.63% Senior Notes that were exchanged for a like amount of 8.63% Senior Notes due April 2031 issued by PSEG.
Debt Covenants
PSEG Power’s existing credit agreements and senior notes contain covenants restricting the ability of PSEG Power and its subsidiaries that guarantee its indebtedness from consummating certain mergers, consolidations or asset sales. The disposal of PSEG Power’s non-nuclear generating fleet could, depending on the structure of such transaction, among other factors, trigger a default under one or more of these provisions. For these reasons, or for other reasons, PSEG Power may decide, or be required, to seek amendments or waivers under its credit agreements and may redeem its outstanding senior notes, at a price equal to the principal amount thereof plus a make-whole premium. Whether such amendments, waivers or redemptions will be required will depend on a number of factors, including the structure of any transaction resulting from the strategic review, and any actual redemption price would depend on the applicable treasury rate in effect at such time. It is likewise possible that the ultimate outcome of the process may result in a transaction, or may result in no transaction at all, where the PSEG Power notes are not redeemed. If PSEG Power is required to redeem its senior notes, the cost of such redemption would be material.
Short-Term Liquidity
PSEG meets its short-term liquidity requirements, as well as those of PSEG Power, primarily with cash and through the issuance of commercial paper.paper and, from time to time, short-term loans. PSE&G maintains its own separate commercial paper program to meet its short-term liquidity requirements. Each commercial paper program is fully back-stopped by its own separate credit facilities.
The commitments under the $4.2 billion credit facilities are provided by a diverse bank group. As of December 31, 2017,2020, the total available credit capacity was $3.5$3.3 billion.
As of December 31, 2017,2020, no single institution represented more than 8%9% of the total commitments in the credit facilities.
As of December 31, 2017,2020, the total credit capacity was in excess of the anticipated maximum liquidity requirements over PSEG’s 12-month planning horizon.horizon, including access to capital to meet redemptions.
Each of the credit facilities is restricted as to availability and use to the specific companies as listed in the following table; however, if necessary, the PSEG facilities can also be used to support our subsidiaries’ liquidity needs.
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The total credit facilities and available liquidity as of December 31, 20172020 were as follows:
As of December 31, 2020 
Company/FacilityTotal
Facility		Usage (D)Available
Liquidity		Expiration
Date		Primary Purpose
Millions
PSEG
5-year Credit Facilities (A)$1,500 $665 $835 Mar 2024Commercial Paper Support/Funding/Letters of Credit
Total PSEG$1,500 $665 $835 
PSE&G
5-year Credit Facility (B)$600 $117 $483 Mar 2024Commercial Paper Support/Funding/Letters of Credit
Total PSE&G$600 $117 $483 
PSEG Power
3-year Letter of Credit Facility$100 $48 $52 Sept 2021Letters of Credit
3-year Letter of Credit Facility100 81 19 Sept 2022Letters of Credit
5-year Credit Facilities (C)1,900 39 1,861 Mar 2024Funding/Letters of Credit
Total PSEG Power$2,100 $168 $1,932 
Total$4,200 $950 $3,250 
             
   As of December 31, 2017   
 Company/Facility 
Total
Facility
 Usage 
Available
Liquidity
 
Expiration
Date
 Primary Purpose 
   Millions     
 PSEG           
 5-year Credit Facilities (A) $1,500
 $556
 $944
 Mar 2022 Commercial Paper Support/Funding/Letters of Credit (LC) 
 Total PSEG $1,500
 $556
 $944
     
 PSE&G           
 5-year Credit Facility (A) $600
 $15
 $585
 Mar 2022 Commercial Paper Support/Funding/Letters of Credit 
 Total PSE&G $600
 $15
 $585
     
 Power           
 3-year LC Facilities $200
 $112
 $88
 Mar 2020 Letters of Credit 
 5-year Credit Facilities 1,900
 39
 1,861
 Mar 2022 Funding/Letters of Credit 
 Total Power $2,100
 $151
 $1,949
     
 Total $4,200
 $722
 $3,478
     
             
(A)The primary use of PSEG’s and PSE&G’s credit facilities is to support their respective Commercial Paper Programs under which as of December 31, 2017, PSEG had $542 million outstanding at a weighted average interest rate of 1.89%. PSE&G had no amounts outstanding under its Commercial Paper Program as of December 31, 2017.

(A)PSEG facilities will be reduced by $9 million in March 2022.
(B)PSE&G facility will be reduced by $4 million in March 2022.
141(C)PSEG Power facilities will be reduced by $12 million in March 2022.
Table(D)The primary use of ContentsPSEG’s and PSE&G’s credit facilities is to support their respective Commercial Paper Programs, under which as of December 31, 2020, PSEG had $663 million outstanding at a weighted average interest rate of 0.33%. PSE&G had $100 million outstanding at a weighted average interest rate of 0.28% under its Commercial Paper Program as of December 31, 2020.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Except as otherwise noted in the table above, in March 2020, PSEG, PSE&G and PSEG Power and their respective lenders agreed to extend the expiration dates on their credit agreements from March 2023 to March 2024.

Short-Term Loans
PSEG
In March 2020, PSEG entered into a $300 million, 364-day variable rate term loan agreement, which was prepaid in January 2021. In April 2020, PSEG entered into two 364-day variable rate term loan agreements for $200 million and $300 million which were prepaid in August 2020.
Fair Value of Debt
The estimated fair values, carrying amounts and methods used to determine fair value of long-term debt as of December 31, 20172020 and 20162019 are included in the following table and accompanying notes as of December 31, 20172020 and 2016.2019. See Note 17.19. Fair Value Measurements for more information on fair value guidance and the hierarchy that prioritizes the inputs to fair value measurements into three levels.
 December 31, 2020December 31, 2019
 Carrying
Amount		Fair
Value 		Carrying
Amount		Fair
Value 
 Millions
Long-Term Debt:
PSEG (A) (B)$2,929 $3,092 $2,441 $2,479 
PSE&G (B)10,909 13,372 9,827 11,107 
PSEG Power (B)2,342 2,679 2,840 3,137 
Total Long-Term Debt$16,180 $19,143 $15,108 $16,723 
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   December 31, 2017 December 31, 2016 
   
Carrying
Amount
 
Fair
Value 
 
Carrying
Amount
 
Fair
Value 
 
   Millions 
 Long-Term Debt:         
 PSEG (A) (B) $2,091
 $2,081
 $1,195
 $1,185
 
 PSE&G (B) 8,591
 9,322
 7,818
 8,240
 
 Power (B) 2,386
 2,659
 2,382
 2,578
 
   $13,068
 $14,062
 $11,395
 $12,003
 
           
(A)Includes a floating-rate term loan of $700 million at PSEG as of December 31, 2019. The fair value of the term loan debt (Level 2 measurement) approximates the carrying value because the interest payments are based on LIBOR rates that are reset monthly and the debt is redeemable at face value by PSEG at any time.
(A)As of December 31, 2017 and 2016, fair value includes floating rate term loans of $700 million and $500 million, respectively. The fair values of the term loan debt (Level 2 measurement) approximate the carrying values because the interest payments are based on LIBOR rates that are reset monthly and the debt is redeemable at face value by PSEG at any time.
(B)Given that these bonds do not trade actively, the fair value amounts of taxable debt securities (primarily Level 2 measurements) are generally determined by a valuation model that is based on a conventional discounted cash flow methodology and utilizes assumptions of current market pricing curves. In order to incorporate the credit risk into the discount rates, pricing is obtained (i.e. U.S. Treasury rate plus credit spread) based on expected new issue pricing across each of the companies’ respective debt maturity spectrum. The credit spreads of various tenors obtained from this information are added to the appropriate benchmark U.S. Treasury rates in order to determine the current market yields for the various tenors. The yields are then converted into discount rates of various tenors that are used for discounting the respective cash flows of the same tenor for each bond or note.
(B)Given that these bonds do not trade actively, the fair value amounts of taxable debt securities (primarily Level 2 measurements) are generally determined by a valuation model that is based on a conventional discounted cash flow methodology. The fair value amounts above do not represent the price at which the outstanding debt may be called for redemption by each issuer under their respective debt agreements.
Note 15.17. Schedule of Consolidated Capital Stock
 As of December 31,
 Outstanding SharesBook Value
 2020201920202019
 Millions
PSEG Common Stock (no par value) (A)
Authorized 1,000 shares504 504 $4,170 $4,172 
           
   As of December 31, 
   Outstanding Shares Book Value 
   2017 2016 2017 2016 
   Millions 
 PSEG Common Stock (no par value) (A)         
 Authorized 1,000 shares 505
 505
 $4,198
 $4,219
 
           
(A)PSEG did not issue any new shares under the Dividend Reinvestment and Stock Purchase Plan or the Employee Stock Purchase Plan (ESPP) in 2020 or 2019.
(A)PSEG did not issue any new shares under the Dividend Reinvestment and Stock Purchase Plan (DRASPP) or the Employee Stock Purchase Plan (ESPP) in 2017 or 2016.
As of December 31, 2017,2020, PSE&G had an aggregate of 7.5 million shares of $100$100 par value and 10 million shares of $25$25 par value Cumulative Preferred Stock, which were authorized and unissued and which, upon issuance, may or may not provide for mandatory sinking fund redemption.

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Note 16.18. Financial Risk Management Activities
Derivative accounting guidance requires that a derivative instrument be recognized as either an asset or a liability at fair value, with changes in fair value of the derivative recognized in earnings each period. Other accounting treatments are available through special election and designation provided that the derivative instrument meets specific, restrictive criteria, both at the time of designation and on an ongoing basis. These alternative permissible treatments include NPNS, cash flow hedge and fair value hedge accounting. PSEG, PSEG Power and PSE&G have applied the NPNS scope exception to certain derivative contracts for the forward sale of generation, power procurement agreements and fuel agreements. PSEG uses interest rate swaps and other derivatives, which are designated and effectivequalifying as cash flow or fair value hedges. PSEG Power and PSE&G enterenters into additional contracts that are derivatives, but are not designated as either cash flow hedges or fair value hedges. These transactions are economic hedges and are recorded at fair market value.value with changes recognized in earnings.
Commodity Prices
Within PSEG and its affiliate companies, PSEG Power has the most exposure to commodity price risk. PSEG Power is exposed to commodity price risk primarily relating to changes in the market price of electricity, fossil fuels and other commodities. Fluctuations in market prices result from changes in supply and demand, fuel costs, market conditions, weather, state and federal regulatory policies, environmental policies, transmission availability and other factors. PSEG Power uses a variety of derivative and non-derivative instruments, such as financial options, futures, swaps, fuel purchases and forward purchases and sales of electricity, to manage the exposure to fluctuations in commodity prices and optimize the value of PSEG Power’s expected generation. PSEG Power also uses derivatives to hedge a portion of its anticipated BGSS obligations with PSE&G. For additional information see Note 13.15. Commitments and Contingent Liabilities. Changes in the fair market value of these derivative contracts are recorded in earnings.
Interest Rates
PSEG, PSEG Power and PSE&G are subject to the risk of fluctuating interest rates in the normal course of business. Exposure to this risk is managed by targeting a balanced debt maturity profile which limits refinancing in any given period or interest rate environment. In addition, they have used a mix of fixed and floating rate debt and interest rate swaps.
Fair Value Hedges
PSEG enters into fair value hedges to convert fixed-rate debt into variable-rate debt. The changes in fair value of the interest rate swaps are fully offset by changes in the fair value of the underlying forecasted interest payments of the debt. There were no outstanding interest rate swaps as of December 31, 2017 or 2016. The fair value hedges reduced interest expense by $6 million and $19 million for the years ended December 31, 2016 and 2015, respectively.
Cash Flow Hedges
PSEG uses interest rate swaps and other derivatives, which are designated and effective as cash flow hedges, to manage its exposure to the variability of cash flows, primarily related to variable-rate debt instruments. There were no outstanding interest rate hedges as of December 31, 2017.2020. As of December 31, 2016,2019, PSEG had interest rate hedges outstanding totaling $500 $700
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

million. These hedges converted PSEG’s $500$700 million variable ratevariable-rate term loan due November 20172020 into a fixed ratefixed-rate loan. As of December 31, 2016,2019, the fair value of these hedges was $1 million and there was no ineffectiveness. $(5) million.
The Accumulated Other Comprehensive Income (Loss) (after tax) related to existingoutstanding and terminated interest rate derivatives designated as cash flow hedges was immaterial as of December 31, 2017$(9) million and $2$(15) million as of December 31, 2016.2020 and December 31, 2019, respectively. The after-tax unrealized gainslosses on these hedges expected to be reclassified to earnings during the next 12 months is immaterial.are $(3) million.
Fair Values of Derivative Instruments
The following are the fair values of derivative instruments on the Consolidated Balance Sheets. The following tables also include disclosures for offsetting derivative assets and liabilities which are subject to a master netting or similar agreement. In general, the terms of the agreements provide that in the event of an early termination the counterparties have the right to offset amounts owed or owing under that and any other agreement with the same counterparty. Accordingly, and in accordance with PSEG’s accounting policy, these positions are offset on the Consolidated Balance Sheets of PSEG Power and PSEG. For additional information see Note 17.19. Fair Value Measurements.

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The following tabular disclosure does not include the offsetting of trade receivables and payables.
               
  As of December 31, 2017 
  Power (A) PSE&G (A) PSEG (A) Consolidated 
   Not Designated     Not Designated 
Cash Flow
Hedges
   
 Balance Sheet Location 
Energy-
Related
Contracts
 
Netting
(B)
 
Total
Power
 
Energy-
Related
Contracts
 
Interest
Rate
Swaps
 
Total
Derivatives
 
  Millions 
 Derivative Contracts             
 Current Assets $391
 $(362) $29
 $—
 $—
 $29
 
 Noncurrent Assets 78
 (71) 7
 —
 —
 7
 
 Total Mark-to-Market Derivative Assets $469
 $(433) $36
 $—
 $—
 $36
 
 Derivative Contracts             
 Current Liabilities $(403) $387
 $(16) $—
 $—
 $(16) 
 Noncurrent Liabilities (95) 90
 (5) —
 —
 (5) 
 Total Mark-to-Market Derivative (Liabilities) $(498) $477
 $(21) $—
 $—
 $(21) 
 Total Net Mark-to-Market Derivative Assets (Liabilities) $(29) $44
 $15
 $—
 $—
 $15
 
               
 As of December 31, 2020
PSEG Power (A)Consolidated
 Not Designated   
Balance Sheet LocationEnergy-
Related
Contracts		Netting
(B)		Total
PSEG Power		Total
Derivatives
 Millions
Derivative Contracts
Current Assets$464 $(404)$60 $60 
Noncurrent Assets93 (84)9 9 
Total Mark-to-Market Derivative Assets$557 $(488)$69 $69 
Derivative Contracts
Current Liabilities$(412)$391 $(21)$(21)
Noncurrent Liabilities(109)105 (4)(4)
Total Mark-to-Market Derivative (Liabilities)$(521)$496 $(25)$(25)
Total Net Mark-to-Market Derivative Assets (Liabilities)$36 $8 $44 $44 
149
               
  As of December 31, 2016 
  Power (A) PSE&G (A) PSEG (A) Consolidated 
   Not Designated     Not Designated 
Fair Value
Hedges
   
 Balance Sheet Location 
Energy-
Related
Contracts
 
Netting
(B)
 
Total
Power
 
Energy-
Related
Contracts
 
Interest
Rate
Swaps
 
Total
Derivatives
 
  Millions 
 Derivative Contracts             
 Current Assets $435
 $(273) $162
 $—
 $1
 $163
 
 Noncurrent Assets 122
 (98) 24
 —
 —
 24
 
 Total Mark-to-Market Derivative Assets $557
 $(371) $186
 $—
 $1
 $187
 
 Derivative Contracts             
 Current Liabilities $(285) $277
 $(8) $(5) $—
 $(13) 
 Noncurrent Liabilities (98) 95
 (3) —
 —
 (3) 
 Total Mark-to-Market Derivative (Liabilities) $(383) $372
 $(11) $(5) $—
 $(16) 
 Total Net Mark-to-Market Derivative Assets (Liabilities) $174
 $1
 $175
 $(5) $1
 $171
 
               
(A)Substantially all of Power's and PSEG's derivative instruments are contracts subject to master netting agreements. Contracts not subject to master netting or similar agreements are immaterial and did not have any collateral posted or received as of December 31, 2017 and 2016. PSE&G does not have any derivative contracts subject to master netting or similar agreements.
(B)Represents the netting of fair value balances with the same counterparty (where the right of offset exists) and the application of collateral. All cash collateral received or posted that has been allocated to derivative positions, where the right of offset exists, has been offset on the Consolidated Balance Sheets. As of December 31, 2017, and 2016, Power had net cash collateral/margin payments to counterparties of $146 million and $56 million,

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 As of December 31, 2019
PSEG Power (A)PSEG (A)Consolidated
 Not Designated  Cash Flow
Hedges		 
Balance Sheet LocationEnergy-
Related
Contracts		Netting
(B)		Total
PSEG Power		Interest
Rate
Swaps		Total
Derivatives
 Millions
Derivative Contracts
Current Assets$636 $(523)$113 $0 $113 
Noncurrent Assets163 (139)24 0 24 
Total Mark-to-Market Derivative Assets$799 $(662)$137 $0 $137 
Derivative Contracts
Current Liabilities$(553)$522 $(31)$(5)$(36)
Noncurrent Liabilities(139)138 (1)0 (1)
Total Mark-to-Market Derivative (Liabilities)$(692)$660 $(32)$(5)$(37)
Total Net Mark-to-Market Derivative Assets (Liabilities)$107 $(2)$105 $(5)$100 
(A)    Substantially all of PSEG Power’s and PSEG’s derivative instruments are contracts subject to master netting agreements. Contracts not subject to master netting or similar agreements are immaterial and did not have any collateral posted or received as of December 31, 2020 and 2019.
(B)    Represents the netting of fair value balances with the same counterparty (where the right of offset exists) and the application of cash collateral. All cash collateral (received) posted that has been allocated to derivative positions, where the right of offset exists, has been offset on the Consolidated Balance Sheets. As of December 31, 2020 and 2019, PSEG Power had net cash collateral payments to counterparties of $54 million and $44 million, respectively. Of these net cash collateral/margincollateral (receipts) payments, $44$8 million as of December 31, 20172020 and $1$(2) million as of December 31, 20162019 were netted against the corresponding net derivative contract positions. Of the $44$8 million as of December 31, 2017, $(3)2020, $(13) million was netted against current assets, $28 million was netted against current liabilities and $19$21 million was netted against noncurrent liabilities. Of the $1$(2) million as of December 31, 2016, $(3)2019, $(1) million was netted against current assets and $(1) million was netted against noncurrent assets and $4 million was netted against current liabilities.assets.
Certain of PSEG Power’s derivative instruments contain provisions that require PSEG Power to post collateral. This collateral may be posted in the form of cash or credit support with thresholds contingent upon PSEG Power’s credit rating from each of the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. These credit risk-related contingent features stipulate that if PSEG Power were to be downgraded to a below investment grade rating by S&P or Moody’s, it would be required to provide additional collateral. A below investment grade credit rating for PSEG Power would represent a three level downgrade from its current S&P or Moody’s ratings. This incremental collateral requirement can offset collateral requirements related to other derivative instruments that are assets with the same counterparty, where the contractual right of offset exists under applicable master agreements. PSEG Power also enters into commodity transactions on the New York Mercantile Exchange (NYMEX) and Intercontinental Exchange (ICE). The NYMEX and ICE clearing houses act as counterparties to each trade. Transactions on the NYMEX and ICE must adhere to comprehensive collateral and margin requirements.
The aggregate fair value of all derivative instruments with credit risk-related contingent features in a liability position that are not fully collateralized (excluding transactions on the NYMEX and ICE that are fully collateralized) was $30$28 million and $19$35 million as of December 31, 20172020 and 2016,2019, respectively. As of December 31, 20172020 and 2016,2019, PSEG Power had the contractual right of offset of $13$3 million and $9$2 million, respectively, related to derivative instruments that are assets with the same counterparty under master agreements and net of margin posted. If PSEG Power had been downgraded to a below investment grade rating, it would have had additional collateral obligations of $17$25 million and $10$33 million as of December 31, 20172020 and 2016,2019, respectively, related to its derivatives, net of the contractual right of offset under master agreements and the application of collateral.
The following shows the effect on the Consolidated Statements of Operations and on Accumulated Other Comprehensive Income (AOCI)Loss (AOCL) of derivative instruments designated as cash flow hedges for the years ended December 31, 2017, 20162020, 2019 and 2015.2018.
150
                 
   
Amount of Pre-Tax
Gain (Loss)
Recognized in AOCI on Derivatives
(Effective Portion)
 
Location of
Pre-Tax
Gain (Loss)
Reclassified from
AOCI into Income
 
Amount of Pre-Tax
Gain (Loss)
Reclassified from
AOCI into Income
(Effective Portion)
 
 Derivatives in Cash Flow Hedging Relationships
Years Ended
December 31,
   
Years Ended
December 31,
 
   2017 2016 2015    2017 2016 2015 
   Millions   Millions 
 PSEG               
 Energy-Related Contracts $—
 $—
 $3
 Operating Revenues $—
 $—
 $20
 
 Interest Rate Swaps —
 3
 —
 Interest Expense 3
 —
 —
 
 Total PSEG $—
 $3
 $3
   $3
 $—
 $20
 
 Power               
 Energy-Related Contracts $—
 $—
 $3
 Operating Revenues $—
 $—
 $20
 
 Total Power $—
 $—
 $3
   $—
 $—
 $20
 
                 
There were no pre-tax gain (loss) recognized in income on derivatives (ineffective portion) as of December 31, 2017, 2016 and 2015.



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Amount of Pre-Tax
Gain (Loss)
Recognized in AOCL on Derivatives		Location of
Pre-Tax
Gain (Loss)
Reclassified from
AOCL into Income		Amount of Pre-Tax
Gain (Loss)
Reclassified from
AOCL into Income
Derivatives in Cash Flow Hedging RelationshipsYears Ended
December 31,		Years Ended
December 31,
 202020192018202020192018
 MillionsMillions
PSEG
Interest Rate Swaps$(6)$(23)$(2)Interest Expense$(14)$(4)$0 
Total PSEG$(6)$(23)$(2)$(14)$(4)$0 
The effect of interest rate cash flow hedges is recorded in Interest Expense in PSEG’s Consolidated Statement of Operations. For the year ended December 31, 2020, the amount of gain or loss on interest rate hedges reclassified from Accumulated Other Comprehensive Income (Loss) into income was $(10) million and $(3) million after tax as of December 31, 2020 and 2019, respectively and immaterial as of December 31, 2018.
The following reconciles the AOCIAccumulated Other Comprehensive Income (Loss) for derivative activity included in the Accumulated Other Comprehensive LossAOCL of PSEG on a pre-tax and after-tax basis.
Accumulated Other Comprehensive Income (Loss)Pre-TaxAfter-Tax
 Millions
Balance as of December 31, 2018$(2)$(1)
Loss Recognized in AOCI(23)(17)
Less: Loss Reclassified into Income4 3 
Balance as of December 31, 2019$(21)$(15)
Loss Recognized in AOCI(6)(4)
Less: Loss Reclassified into Income14 10 
Balance as of December 31, 2020$(13)$(9)
       
 Accumulated Other Comprehensive Income Pre-Tax After-Tax 
   Millions 
 Balance as of December 31, 2015 $—
 $—
 
 Gain Recognized in AOCI 3
 2
 
 Less: Gain Reclassified into Income —
 —
 
 Balance as of December 31, 2016 $3
 $2
 
 Gain Recognized in AOCI —
 —
 
 Less: Gain Reclassified into Income (3) (2) 
 Balance as of December 31, 2017 $—
 $—
 
       
The following shows the effect on the Consolidated Statements of Operations of derivative instruments not designated as hedging instruments or as NPNS for the years ended December 31, 2017, 20162020, 2019 and 2015.2018. PSEG Power’s derivative contracts reflected in this table include contracts to hedge the purchase and sale of electricity and natural gas, and the purchase of fuel. The table does not include contracts whichthat PSEG Power has designated as NPNS, such as its BGS contracts and certain other energy supply contracts that it has with other utilities and companies with retail load.
Derivatives Not Designated as HedgesLocation of Pre-Tax
Gain (Loss)
Recognized in Income
on Derivatives		Pre-Tax Gain (Loss)
Recognized in Income
on Derivatives
  Years Ended December 31,
  202020192018
  Millions
PSEG Power
Energy-Related ContractsOperating Revenues$279 $560 $(182)
Energy-Related ContractsEnergy Costs(142)(119)(9)
Total PSEG and PSEG Power$137 $441 $(191)
151
           
 Derivatives Not Designated as Hedges 
Location of Pre-Tax
Gain (Loss)
Recognized in Income
on Derivatives
 
Pre-Tax Gain (Loss)
Recognized in Income
on Derivatives
 
     Years Ended December 31, 
     2017 2016 2015 
     Millions 
 PSEG and Power         
 Energy-Related Contracts Operating Revenues $72
 $230
 $412
 
 Energy-Related Contracts Energy Costs (17) (8) (8) 
 Total PSEG and Power   $55
 $222
 $404
 
           

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table summarizes the net notional volume purchases/(sales) of open derivative transactions by commodity as of December 31, 20172020 and 2016.2019.
             
 Type Notional Total PSEG Power PSE&G 
   Millions 
 As of December 31, 2017           
 Natural Gas Dth 154
 —
 154
 —
 
 Electricity MWh (63) —
 (63) —
 
 Financial Transmission Rights (FTRs) MWh 6
 —
 6
 —
 
 As of December 31, 2016           
 Natural Gas Dth 122
 —
 113
 9
 
 Electricity MWh (44) —
 (44) —
 
 FTRs MWh 9
 —
 9
 —
 
 Interest Rate Swaps U.S. Dollars 500
 500
 —
 —
 
             

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TypeNotionalTotalPSEGPSEG PowerPSE&G
 Millions
As of December 31, 2020
Natural GasDekatherm (Dth)321 0 321 0 
ElectricityMWh(66)0 (66)0 
Financial Transmission Rights (FTRs)MWh20 0 20 0 
As of December 31, 2019
Natural GasDth341 0 341 0 
ElectricityMWh(62)0 (62)0 
FTRsMWh13 0 13 0 
Interest Rate SwapsU.S. Dollars700 700 0 0 
Credit Risk
Credit risk relates to the risk of loss that PSEG Power would incur as a result of non-performance by counterparties pursuant to the terms of their contractual obligations. PSEG has established credit policies that it believes significantly minimize credit risk. These policies include an evaluation of potential counterparties’ financial condition (including credit rating), collateral requirements under certain circumstances and the use of standardized agreements, which allow for the netting of positive and negative exposures associated with a single counterparty. In the event of non-performance or non-payment by a major counterparty, there may be a material adverse impact on PSEG Power’s and PSEG’s financial condition, results of operations or net cash flows.
As of December 31, 2017, 99% of the net credit exposure for Power’s operations was with investment grade counterparties. Credit exposure is defined as any positive results of netting accounts receivable/accounts payable and the forward value of open positions (which includes all financial instruments including derivatives, NPNS and non-derivatives).
The following table provides information on PSEG Power’s credit risk from others,wholesale counterparties, net of collateral, as of December 31, 2017.2020. It further delineates that exposure by the credit rating of the counterparties, which is determined by the lowest rating from S&P, Moody’s or an internal scoring model. In addition, it provides guidance on the concentration of credit risk to individual counterparties and an indication of the quality of PSEG Power’s credit risk by credit rating of the counterparties.
As of December 31, 2020, 88% of the net credit exposure for PSEG Power’s wholesale operations was with investment grade counterparties. Credit exposure is defined as any positive results of netting accounts receivable/accounts payable and the forward value of open positions (which includes all financial instruments including derivatives, NPNS and non-derivatives).
              
 Rating 
Current
Exposure
 
Securities
held as
Collateral
 
Net
Exposure
 
Number of
Counterparties
>10%
 
Net Exposure of
Counterparties
>10%
  
   Millions   Millions  
 Investment Grade $329
 $25
 $304
 1
 $204
(A)  
 Non-Investment Grade 3
 1
 2
 —
 —
   
 Total $332
 $26
 $306
 1
 $204
   
              
RatingCurrent
Exposure		Securities
held as
Collateral		Net
Exposure		Number of
Counterparties
>10%		Net Exposure of
Counterparties
>10% (A)
 Millions Millions
Investment Grade$337 $39 $298 1 $169 
Non-Investment Grade40 0 40 1 40 
Total$377 $39 $338 2 $209 
(A)Represents net exposure with PSE&G.
(A)Represents net exposure of $169 million with PSE&G and $40 million with a non-affiliated counterparty.
As of December 31, 2017,2020, collateral held from counterparties where PSEG Power had credit exposure included $1includes $4 million in cash collateral and $25$35 million in letters of credit.
As of December 31, 2017,2020, PSEG Power had 152135 active counterparties.
PSE&G’s supplier master agreements are approved by the BPU and govern the terms of its electric supply procurement contracts. These agreements define a supplier’s performance assurance requirements and allow a supplier to meet its credit requirements with a certain amount of unsecured credit. The amount of unsecured credit is determined based on the supplier’s credit ratings from the major credit rating agencies and the supplier’s tangible net worth. The credit position is based on the initial market price, which is the forward price of energy on the day the procurement transaction is executed, compared to the forward price curve for energy on the valuation day. To the extent that the forward price curve for energy exceeds the initial market price, the supplier is required to post a parental guaranty or other security instrument such as a letter of credit or cash, as collateral to the extent the credit exposure is greater than the supplier’s unsecured credit limit. As of December 31, 2017, 2020,
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

primarily all of the posted collateral was in the form of parental guarantees. The unsecured credit used by the suppliers represents PSE&G’s net credit exposure. PSE&G’s BGS suppliers’ credit exposure is calculated each business day. As of December 31, 2017,2020, PSE&G had no net credit exposure with suppliers, including PSEG Power.
PSE&G is permitted to recover its costs of procuring energy through the BPU-approved BGS tariffs. PSE&G’s counterparty credit risk is mitigated by its ability to recover realized energy costs through customer rates.

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Note 17.19. Fair Value Measurements
Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Accounting guidance for fair value measurement emphasizes that fair value is a market-based measurement, not an entity-specific measurement, and establishes a fair value hierarchy that distinguishes between assumptions based on market data obtained from independent sources and those based on an entity’s own assumptions. The hierarchy prioritizes the inputs to fair value measurement into three levels:
Level 1—measurements utilize quoted prices (unadjusted) in active markets for identical assets or liabilities that PSEG, PSE&G and PSEG Power have the ability to access. These consist primarily of listed equity securities and money market mutual funds, as well as natural gas futures contracts executed on NYMEX.
Level 2—measurements include quoted prices for similar assets and liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, and other observable inputs such as interest rates and yield curves that are observable at commonly quoted intervals. These consist primarily of non-exchange traded derivatives such as forward contracts or options and most fixed income securities.
Level 3—measurements use unobservable inputs for assets or liabilities, based on the best information available and might include an entity’s own data and assumptions. In some valuations, the inputs used may fall into different levels of the hierarchy. In these cases, the financial instrument’s level within the fair value hierarchy is based on the lowest level of input that is significant to the fair value measurement. As of December 31, 2017, these consistedThese consist primarily of certain electric load contracts and gas contracts.
Certain derivative transactions may transfer from Level 2 to Level 3 if inputs become unobservable and internal modeling techniques are employed to determine fair value. Conversely, measurements may transfer from Level 3 to Level 2 if the inputs become observable.
The following tables present information about PSEG’s, PSE&G’s and PSEG Power’s respective assets and (liabilities) measured at fair value on a recurring basis as of December 31, 20172020 and December 31, 2016,2019, including the fair value measurements and the levels of inputs used in determining those fair values. Amounts shown for PSEG include the amounts shown for PSE&G and PSEG Power.

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 Recurring Fair Value Measurements as of December 31, 2020
DescriptionTotal Netting  (D)Quoted Market Prices for Identical Assets
(Level 1)		Significant Other Observable Inputs (Level 2)Significant Unobservable Inputs
(Level 3)
Millions
PSEG
Assets:
Cash Equivalents (A)$312 $0 $312 $0 $0 
Derivative Contracts:
Energy-Related Contracts (B)$69 $(488)$26 $519 $12 
NDT Fund (C)
Equity Securities$1,352 $0 $1,351 $1 $0 
Debt Securities—U.S. Treasury$239 $0 $0 $239 $0 
Debt Securities—Govt Other$342 $0 $0 $342 $0 
Debt Securities—Corporate$566 $0 $0 $566 $0 
Rabbi Trust (C)
Equity Securities$31 $0 $31 $0 $0 
Debt Securities—U.S. Treasury$59 $0 $0 $59 $0 
Debt Securities—Govt Other$41 $0 $0 $41 $0 
Debt Securities—Corporate$135 $0 $0 $135 $0 
Liabilities:
Derivative Contracts:
Energy-Related Contracts (B)$(25)$496 $(33)$(483)$(5)
PSE&G
Assets:
Cash Equivalents (A)$50 $0 $50 $0 $0 
Rabbi Trust (C)
Equity Securities$6 $0 $6 $0 $0 
Debt Securities—U.S. Treasury$11 $0 $0 $11 $0 
Debt Securities—Govt Other$8 $0 $0 $8 $0 
Debt Securities—Corporate$26 $0 $0 $26 $0 
PSEG Power
Assets:
Derivative Contracts:
Energy-Related Contracts (B)$69 $(488)$26 $519 $12 
NDT Fund (C)
Equity Securities$1,352 $0 $1,351 $1 $0 
Debt Securities—U.S. Treasury$239 $0 $0 $239 $0 
Debt Securities—Govt Other$342 $0 $0 $342 $0 
Debt Securities—Corporate$566 $0 $0 $566 $0 
Rabbi Trust (C)
Equity Securities$8 $0 $8 $0 $0 
Debt Securities—U.S. Treasury$15 $0 $0 $15 $0 
Debt Securities—Govt Other$10 $0 $0 $10 $0 
Debt Securities—Corporate$33 $0 $0 $33 $0 
Liabilities:
Derivative Contracts:
Energy-Related Contracts (B)$(25)$496 $(33)$(483)$(5)
154
             
   Recurring Fair Value Measurements as of December 31, 2017 
 Description Total  Netting  (E) 
Quoted Market Prices for Identical Assets
(Level 1)
 Significant Other Observable Inputs (Level 2) 
Significant Unobservable Inputs
(Level 3)
 
   Millions 
 PSEG           
 Assets:           
 Cash Equivalents (A) $223
 $—
 $223
 $—
 $—
 
 Derivative Contracts:           
 Energy-Related Contracts (B) $36
 $(433) $15
 $442
 $12
 
 NDT Fund (D)           
 Equity Securities $1,055
 $—
 $1,053
 $2
 $—
 
 Debt Securities—U.S. Treasury $314
 $—
 $—
 $314
 $—
 
 Debt Securities—Govt Other $270
 $—
 $—
 $270
 $—
 
 Debt Securities—Corporate $402
 $—
 $—
 $402
 $—
 
 Other Securities $92
 $—
 $92
 $—
 $—
 
 Rabbi Trust (D)           
 Equity Securities—Mutual Funds $25
 $—
 $25
 $—
 $—
 
 Debt Securities—U.S. Treasury $51
 $—
 $—
 $51
 $—
 
 Debt Securities—Govt Other $34
 $—
 $—
 $34
 $—
 
 Debt Securities—Corporate $119
 $—
 $—
 $119
 $—
 
 Other Securities $2
 $—
 $2
 $—
 $—
 
 Liabilities:           
 Derivative Contracts:           
 Energy-Related Contracts (B) $(21) $477
 $(8) $(485) $(5) 
 PSE&G           
 Assets:           
 Cash Equivalents (A) $223
 $—
 $223
 $—
 $—
 
 Rabbi Trust (D)           
 Equity Securities—Mutual Funds $5
 $—
 $5
 $—
 $—
 
 Debt Securities—U.S. Treasury $10
 $—
 $—
 $10
 $—
 
 Debt Securities—Govt Other $7
 $—
 $—
 $7
 $—
 
 Debt Securities—Corporate $24
 $—
 $—
 $24
 $—
 
 Other Securities $—
 $—
 $—
 $—
 $—
 
 Power           
 Assets:           
 Derivative Contracts:           
 Energy-Related Contracts (B) $36
 $(433) $15
 $442
 $12
 
 NDT Fund (D)           
 Equity Securities $1,055
 $—
 $1,053
 $2
 $—
 
 Debt Securities—U.S. Treasury $314
 $—
 $—
 $314
 $—
 
 Debt Securities—Govt Other $270
 $—
 $—
 $270
 $—
 
 Debt Securities—Corporate $402
 $—
 $—
 $402
 $—
 
 Other Securities $92
 $—
 $92
 $—
 $—
 
 Rabbi Trust (D)           
 Equity Securities—Mutual Funds $6
 $—
 $6
 $—
 $—
 
 Debt Securities—U.S. Treasury $13
 $—
 $—
 $13
 $—
 
 Debt Securities—Govt Other $8
 $—
 $—
 $8
 $—
 
 Debt Securities—Corporate $30
 $—
 $—
 $30
 $—
 
 Other Securities $—
 $—
 $—
 $—
 $—
 
 Liabilities:           
 Derivative Contracts:           
 Energy-Related Contracts (B) $(21) $477
 $(8) $(485) $(5) 
             


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 Recurring Fair Value Measurements as of December 31, 2019
DescriptionTotal Netting  (D)Quoted Market Prices for Identical Assets
(Level 1)		Significant Other Observable Inputs (Level 2)Significant Unobservable Inputs
(Level 3)
Millions
PSEG
Assets:
Cash Equivalents (A)$50 $0 $50 $0 $0 
Derivative Contracts:
Energy-Related Contracts (B)$137 $(662)$19 $770 $10 
NDT Fund (C)
Equity Securities$1,151 $0 $1,150 $1 $0 
Debt Securities—U.S. Treasury$225 $0 $0 $225 $0 
Debt Securities—Govt Other$352 $0 $0 $352 $0 
Debt Securities—Corporate$486 $0 $0 $486 $0 
Rabbi Trust (C)
Equity Securities$28 $0 $28 $0 $0 
Debt Securities—U.S. Treasury$57 $0 $0 $57 $0 
Debt Securities—Govt Other$47 $0 $0 $47 $0 
Debt Securities—Corporate$114 $0 $0 $114 $0 
Liabilities:
Derivative Contracts:
Energy-Related Contracts (B)$(32)$660 $(43)$(646)$(3)
Interest Rate Swaps (E)$(5)$0 $0 $(5)$0 
PSE&G
Assets:
Rabbi Trust (C)
Equity Securities$5 $0 $5 $0 $0 
Debt Securities—U.S. Treasury$11 $0 $0 $11 $0 
Debt Securities—Govt Other$9 $0 $0 $9 $0 
Debt Securities—Corporate$23 $0 $0 $23 $0 
PSEG Power
Assets:
Derivative Contracts:
Energy-Related Contracts (B)$137 $(662)$19 $770 $10 
NDT Fund (C)
Equity Securities$1,151 $0 $1,150 $1 $0 
Debt Securities—U.S. Treasury$225 $0 $0 $225 $0 
Debt Securities—Govt Other$352 $0 $0 $352 $0 
Debt Securities—Corporate$486 $0 $0 $486 $0 
Rabbi Trust (C)
Equity Securities$8 $0 $8 $0 $0 
Debt Securities—U.S. Treasury$14 $0 $0 $14 $0 
Debt Securities—Govt Other$12 $0 $0 $12 $0 
Debt Securities—Corporate$28 $0 $0 $28 $0 
Liabilities:
Derivative Contracts:
Energy-Related Contracts (B)$(32)$660 $(43)$(646)$(3)
155
             
   Recurring Fair Value Measurements as of December 31, 2016 
 Description Total  Netting  (E) 
Quoted Market Prices for Identical Assets
(Level 1)
 Significant Other Observable Inputs (Level 2) 
Significant Unobservable Inputs
(Level 3)
 
   Millions 
 PSEG           
 Assets:           
 Cash Equivalents (A) $365
 $—
 $365
 $—
 $—
 
 Derivative Contracts:           
 Energy-Related Contracts (B) $186
 $(371) $17
 $533
 $7
 
 Interest Rate Swaps (C) $1
 $—
 $—
 $1
 $—
 
 NDT Fund (D)           
 Equity Securities $957
 $—
 $954
 $3
 $—
 
 Debt Securities—U.S. Treasury $227
 $—
 $—
 $227
 $—
 
 Debt Securities—Govt Other $293
 $—
 $—
 $293
 $—
 
 Debt Securities—Corporate $337
 $—
��$—
 $337
 $—
 
 Other Securities $44
 $—
 $44
 $—
 $—
 
 Rabbi Trust (D)           
 Equity Securities—Mutual Funds $22
 $—
 $22
 $—
 $—
 
 Debt Securities—U.S. Treasury $37
 $—
 $—
 $37
 $—
 
 Debt Securities—Govt Other $66
 $—
 $—
 $66
 $—
 
 Debt Securities—Corporate $91
 $—
 $—
 $91
 $—
 
 Other Securities $1
 $—
 $1
 $—
 $—
 
 Liabilities:           
 Derivative Contracts:           
 Energy-Related Contracts (B) $(16) $372
 $(18) $(364) $(6) 
 PSE&G           
 Assets:           
 Cash Equivalents (A) $365
 $—
 $365
 $—
 $—
 
 Derivative Contracts:           
 Energy Related Contracts (B) $—
 $—
 $—
 $—
 $—
 
 Rabbi Trust (D)           
 Equity Securities—Mutual Funds $5
 $—
 $5
 $—
 $—
 
 Debt Securities—U.S. Treasury $7
 $—
 $—
 $7
 $—
 
 Debt Securities—Govt Other $13
 $—
 $—
 $13
 $—
 
 Debt Securities—Corporate $18
 $—
 $—
 $18
 $—
 
 Other Securities $—
 $—
 $—
 $—
 $—
 
 Liabilities:           
 Derivative Contracts:           
 Energy-Related Contracts (B) $(5) $—
 $—
 $—
 $(5) 
 Power           
 Assets:           
 Derivative Contracts:           
 Energy-Related Contracts (B) $186
 $(371) $17
 $533
 $7
 
 NDT Fund (D)           
 Equity Securities $957
 $—
 $954
 $3
 $—
 
 Debt Securities—U.S. Treasury $227
 $—
 $—
 $227
 $—
 
 Debt Securities—Govt Other $293
 $—
 $—
 $293
 $—
 
 Debt Securities—Corporate $337
 $—
 $—
 $337
 $—
 
 Other Securities $44
 $—
 $44
 $—
 $—
 
 Rabbi Trust (D)           
 Equity Securities—Mutual Funds $5
 $—
 $5
 $—
 $—
 
 Debt Securities—U.S. Treasury $9
 $—
 $—
 $9
 $—
 
 Debt Securities—Govt Other $16
 $—
 $—
 $16
 $—
 
 Debt Securities—Corporate $23
 $—
 $—
 $23
 $—
 
 Other Securities $—
 $—
 $—
 $—
 $—
 
 Liabilities:           
 Derivative Contracts:           
 Energy-Related Contracts (B) $(11) $372
 $(18) $(364) $(1) 
             
(A)Represents money market mutual funds.

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

(A)Represents money market mutual funds.
(B)Level 1—These contracts represent natural gas futures contracts executed on NYMEX, and are being valued solely on settled pricing inputs which come directly from the exchange.
Level 2—Fair values for energy-related contracts are obtained primarily using a market-based approach. Most derivative contracts (forward purchase or sale contracts and swaps) are valued using settled prices from similar assets and liabilities from an exchange, such as NYMEX, ICE and Nodal Exchange, or auction prices. Prices used in the valuation process are also corroborated independently by management to determine that values are based on actual transaction data or, in the absence of transactions, bid and offers for the day. Examples may include certain exchange and non-exchange traded capacity and electricity contracts and natural gas physical or swap contracts based on market prices, basis adjustments and other premiums where adjustments and premiums are not considered significant to the overall inputs.
Level 3—Unobservable inputs are used for the valuation of certain contracts. See “Additional Information Regarding Level 3 Measurements” below for more information on the utilization of unobservable inputs.
(C)Interest rate swaps are valued using quoted prices on commonly quoted intervals, which are interpolated for periods different than the quoted intervals, as inputs to a market valuation model. Market inputs can generally be verified and model selection does not involve significant management judgment.
(D)As of December 31, 2016, the fair value measurement table excludes cash of $1 million, which is part of the NDT Fund. The NDT Fund maintains investments in various equity and fixed income securities classified as “available for sale.” The Rabbi Trust maintains investments in a Russell 3000 index fund and various fixed income securities classified as “available for sale” as of December 31, 2017. The Rabbi Trust maintained investments in an S&P 500 index fund and various securities classified as “available for sale” as of December 31, 2016. These securities are generally valued with prices that are either exchange provided (equity securities) or market transactions for comparable securities and/or broker quotes (fixed income securities).
(C)As of December 31, 2020 and 2019, the fair value measurement table excludes foreign currency of $2 million in the NDT Fund. The NDT Fund maintains investments in various equity and fixed income securities. The Rabbi Trust maintains investments in a Russell 3000 index fund and various fixed income securities. These securities are generally valued with prices that are either exchange provided (equity securities) or market transactions for comparable securities and/or broker quotes (fixed income securities).
Level 1—Investments in marketable equity securities within the NDT Fund are primarily investments in common stocks across a broad range of industries and sectors. Most equity securities are priced utilizing the principal market close price or, in some cases, midpoint, bid or ask price. Other SecuritiesCertain other equity securities in the NDT and Rabbi Trust Funds consist primarily of investments in Dreyfus money market funds which seek a high level of current income as is consistent with the preservation of capital and the maintenance of liquidity. To pursue its goals, the fundfunds normally investsinvest in a diversified portfolioportfolios of high quality, short-term, dollar-denominated debt securities and government securities. The funds’ Net Asset Valuenet asset value is priced and published daily. The Rabbi Trust equityTrust’s Russell 3000 index fund is valued based on quoted prices in an active market.market and can be redeemed daily without restriction.
Level 2—NDT and Rabbi Trust fixed income securities include investment grade corporate bonds, collateralized mortgage obligations, asset-backed securities and certain government and U.S. Treasury obligations or Federal Agency asset-backed securities and municipal bonds with a wide range of maturities. Since many fixed income securities do not trade on a daily basis, they are priced using an evaluated pricing methodology that varies by asset class and reflects observable market information such as the most recent exchange price or quoted bid for similar securities. Market-based standard inputs typically include benchmark yields, reported trades, broker/dealer quotes and issuer spreads. The preferred stocks are not actively traded on a daily basis and therefore, are also priced using an evaluated pricing methodology. Certain short-term investments are valued using observable market prices or market parameters such as time-to-maturity, coupon rate, quality rating and current yield.
(E)Represents the netting of fair value balances with the same counterparty (where the right of offset exists) and the application of collateral. All cash collateral received or posted that has been allocated to derivative positions, where the right of offset exists, has been offset in the Consolidated Balance Sheets. As of December 31, 2017 and 2016, Power had net cash collateral/margin payments to counterparties of $146 million and $56 million, respectively. Of these net cash collateral/margin payments $44 million as of December 31, 2017 and $1 million as of December 31, 2016 were netted against the corresponding net derivative contract positions. Of the $44 million of cash collateral as of December 31, 2017, $(3) million was netted against assets, and $47 million was netted against liabilities. Of the $1 million of cash collateral as of December 31, 2016, $(3) million was netted against assets and $4 million was netted against liabilities.
(D)Represents the netting of fair value balances with the same counterparty (where the right of offset exists) and the application of collateral. See Note 18. Financial Risk Management Activities for additional detail.
(E)Interest rate swaps are valued using quoted prices on commonly quoted intervals, which are interpolated for periods different than the quoted intervals, as inputs to a market valuation model. Market inputs can generally be verified and model selection does not involve significant management judgment.
Additional Information Regarding Level 3 Measurements
For valuations that include both observable and unobservable inputs, if the unobservable input is determined to be significant to the overall inputs, the entire valuation is categorized in Level 3. This includes derivatives valued using indicative price quotations for contracts with tenors that extend into periods with no observable pricing. In instances where observable data is unavailable, consideration is given to the assumptions that market participants would use in valuing the asset or liability. This includes assumptions about market risks such as liquidity, volatility and contract duration. Such instruments are categorized in

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Level 3 because the model inputs generally are not observable. PSEG’s Risk Management Committee (RMC) approves risk management policies and objectives for risk assessment, control and valuation, counterparty credit approval and the monitoring and reporting of risk exposures. The RMC reports to the Corporate Governance and Audit Committees of the PSEG Board of Directors on the scope of the risk management activities and is responsible for approving all valuation procedures at PSEG. Forward price curves for the power market utilized by Power to manage the portfolio are maintained and reviewed by PSEG’s Enterprise Risk Management market pricing group and used for financial reporting purposes. PSEG considers credit and nonperformancenon-performance risk in the valuation of derivative contracts categorized in Levels 2 and 3, including both historical and current market data, in its assessment of credit and nonperformancenon-performance risk by counterparty. The impacts of credit and nonperformancenon-performance risk were not material to the financial statements.
For PSE&G, the natural gas supply contract is measured at fair value using modeling techniques taking into account the current price
156

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The fair value of PSEG Power’s electric load contracts in which load consumption may change hourly based on demand are measured using certain unobservable inputs, such as historic load variability and, accordingly, are categorized as Level 3. The fair value of PSEG Power’s gas physical contracts at certain illiquid delivery locations are measured using average historical basis and, accordingly, are categorized as Level 3. While these physical gas physical contracts have an unobservable component in their respective forward price curves, the fluctuations in fair value have been driven primarily by changes in the observable inputs. The following tables provide details surrounding significant Level 3 valuations as of December 31, 20172020 and 2016.2019.
               
   Quantitative Information About Level 3 Fair Value Measurements   
 Commodity Level 3 Position Fair Value as of December 31, 2017 
Valuation
Technique(s)
 
Significant
Unobservable  Input
 Range 
       
     Assets (Liabilities)       
     Millions       
 Power             
                Electricity Electric Load Contracts $1
 $(3) Discounted Cash flow Historic Load Variability 0% to +10% 
 Gas Gas Physical Contracts 11
 (2) Discounted Cash flow Average Historical Basis -40% to -10% 
 Total Power   $12
 $(5)       
 Total PSEG   $12
 $(5)       
               
Quantitative Information About Level 3 Fair Value Measurements
CommodityLevel 3  PositionFair Value as of December 31, 2020Valuation
Technique(s)		Significant
Unobservable  Input		RangeArithmetic Average
  Assets(Liabilities)
  Millions  
PSEG Power
ElectricityElectric Load Contracts$12 $0 Discounted Cash flowLoad Shaping Cost0% to 11%4%
GasGas Physical Contracts0 (2)Discounted Cash flowHistorical Basis Adjustment
'-60% to -30%
-43%
ElectricityOther (A)0 (3)
Total PSEG Power$12 $(5)
Total PSEG$12 $(5)
               
   Quantitative Information About Level 3 Fair Value Measurements   
 Commodity Level 3 Position Fair Value as of December 31, 2016 
Valuation
Technique(s)
 
Significant
Unobservable Input
 Range 
       
     Assets (Liabilities)       
     Millions       
 PSE&G             
 Gas  Natural Gas Supply  Contract $—
 $(5) Discounted Cash Flow Transportation Costs $0.60 to $0.80/Dth 
 Total PSE&G   $—
 $(5)       
 Power             
                  Electricity Electric Load Contracts $7
 $(1) Discounted Cash Flow Historic Load Variability 0% to +10% 
 Gas (A) Other —
 —
       
 Total Power   $7
 $(1)       
 Total PSEG   $7
 $(6)       
               
Quantitative Information About Level 3 Fair Value Measurements
CommodityLevel 3 PositionFair Value as of December 31, 2019Valuation
Technique(s)		Significant
Unobservable Input		Range
  Assets(Liabilities)   
  Millions   
PSEG Power
ElectricityElectric Load Contracts$10 $0 Discounted Cash flowHistoric Load Variability0% to 10%
GasGas Physical Contracts0 (3)Discounted Cash flowAverage Historical Basis
‘-50% to 0%
Total PSEG Power$10 $(3)
Total PSEG$10 $(3)
(A)Other is comprised of a heat rate call option and capacity swaps.
(A)Includes gas positions which were immaterial.
SignificantAs of December 31, 2020, significant unobservable inputs listed above would have a direct impact on the fair values of the above Level 3 instruments if they were adjusted. For energy-related contracts in cases where PSEG Power is a seller, an increase in the load variability would

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decrease the fair value. For gas-related contracts in cases where PSEG Power is a buyer, an increase in the average historical basis would increase the fair value.
157

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

A reconciliation of the beginning and ending balances of Level 3 derivative contracts and securities for the years ended December 31, 20172020 and 2016,2019, respectively, follows:
Changes in Level 3 Assets and (Liabilities) Measured at Fair Value on a Recurring Basis
for the Year Ended December 31, 2017
2020
                 
     
Total Gains or (Losses)
Realized/Unrealized
         
 Description Balance as of January 1, 2017 Included  in Income (A) 
Included in
Regulatory  Assets/
Liabilities (B)
 
Purchases,
(Sales)
 
Issuances/
Settlements
(C)
 
Transfers
In/Out (D)
 Balance as of December 31, 2017 
   Millions 
 PSEG               
 Net Derivative Assets (Liabilities) $1
 $26
 $5
 $—
 $(24) $(1) $7
 
 PSE&G               
 Net Derivative Assets (Liabilities) $(5) $—
 $5
 $—
 $—
 $—
 $—
 
 Power               
 Net Derivative Assets (Liabilities) $6
 $26
 $—
 $—
 $(24) $(1) $7
 
                 
DescriptionBalance as of December 31, 2019Total Gains or (Losses)
Realized/Unrealized
Included in Income (A)		Purchases,
(Sales)		Issuances/
Settlements
(B)		Transfers
In/Out (C)		Balance as of December 31, 2020
 
PSEG and PSEG Power
Net Derivative Assets (Liabilities)$7 $16 $0 $(16)$0 $7 
Changes in Level 3 Assets and (Liabilities) Measured at Fair Value on a Recurring Basis
for the Year Ended December 31, 2016
2019
                 
     
Total Gains or (Losses)
Realized/Unrealized
         
 Description Balance as of January 1, 2016 Included  in Income (A) 
Included in
Regulatory  Assets/
Liabilities (B)
 Purchases, (Sales) Issuances/ Settlements (C) Transfers In/Out Balance as of December 31, 2016 
   Millions 
 PSEG               
 Net Derivative Assets (Liabilities) $13
 $13
 $(7) $3
 $(21) $—
 $1
 
 PSE&G               
 Net Derivative Assets (Liabilities) $2
 $—
 $(7) $—
 $—
 $—
 $(5) 
 Power               
 Net Derivative Assets (Liabilities) $11
 $13
 $—
 $3
 $(21) $—
 $6
 
                 
DescriptionBalance as of December 31, 2018Total Gains or (Losses)
Realized/Unrealized
Included in Income (A)		Purchases, (Sales)Issuances/ Settlements (B)Transfers In/Out (C)Balance as of December 31, 2019
 Millions
PSEG and PSEG Power
Net Derivative Assets (Liabilities)$1 $14 $0 $(8)$0 $7 

(A)PSEG’s and Power’s gains(losses) attributable to changes in net derivative assets and liabilities for 2017 include $14 million in Operating Revenues, of which $(9) million is unrealized and $12 million in Energy Costs, all of which is unrealized. For 2016, $25 million is included in Operating Revenues, of which $(5) million is unrealized, and $(12)

(A)Unrealized gains (losses) in the following table represent the change in derivative assets and liabilities still held as of December 31, 2020 and 2019.
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Years Ended December 31,
20202019
Total Gains (Losses)Unrealized Gains (Losses)Total Gains (Losses)Unrealized Gains (Losses)
Millions
PSEG and PSEG Power
Operating Revenues$26 $1 $23 $12 
Energy Costs(10)1 (9)(6)
Total$16 $2 $14 $6 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(B)Includes $(14) million and $(7) million in settlements for derivative contracts in 2020 and 2019.

million is(C)There were no transfers in Energy Costs, all of which is realized.2020 and 2019 to or from Level 3.
(B)Mainly includes gains/losses on PSE&G’s derivative contracts that are not included in either earnings or Accumulated Other Comprehensive Income, as they are deferred as a Regulatory Asset/Liability and are expected to be recovered from/returned to PSE&G’s customers.
(C)Represents $(24) million and $(21) million in settlements for derivative contracts in 2017 and 2016, respectively.
(D)
During the year ended December 31, 2017, $(1) million of net derivatives assets/liabilities were transferred from Level 2 to Level 3.
As of December 31, 2017,2020, PSEG carried $2.6$3.1 billion of net assets that are measured at fair value on a recurring basis, of which $7 million of net assets were measured using unobservable inputs and classified as Level 3 within the fair value hierarchy.
As of December 31, 2016,2019, PSEG carried $2.6 billion of net assets that are measured at fair value on a recurring basis, of which $1$7 million of net assets were measured using unobservable inputs and classified as Level 3 within the fair value hierarchy.
Note 18.20. Stock Based Compensation
PSEG’s Amended and Restated 2004 Long-Term Incentive Plan (LTIP) is a broad-based equity compensation program that provides for grants of various long-term incentive compensation awards, such as stock options, stock appreciation rights, performance share units, restricted stock, restricted stock units, cash awards or any combination thereof. The types of long-term incentive awards that have been granted and remain outstanding under the LTIP are non-qualified options to purchase shares of PSEG’s common stock, restricted stock unit awards and performance share unit awards. The type of equity award that is granted and the details of that award may vary from time to time and is subject to the approval of the Organization and Compensation Committee of PSEG’s Board of Directors (O&CC), the LTIP’s administrative committee.
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The LTIP currently provides for the issuance of equity awards with respect to approximately 16 million shares of common stock. As of December 31, 2017,2020, there were approximately 1413 million shares available for future awards under the LTIP.
Stock Options
Under the LTIP, non-qualified options to acquire shares of PSEG common stock may be granted to officers and other key employees selected by the O&CC. Option awards are granted with an exercise price equal to the market price of PSEG’s common stock at the grant date. The options generally vest over four years of continuous service. Vesting schedules may be accelerated upon the occurrence of certain events, such as a change-in-control (unless substituted with an equity award of equal value), retirement, death or disability. Options are exercisable over a period of time designated by the O&CC (but not prior to one year or longer than ten years from the date of grant) and are subject to such other terms and conditions as the O&CC determines. Payment by option holders upon exercise of an option may be made in cash or, with the consent of the O&CC, by delivering previously acquired shares of PSEG common stock. No options have been issuedgranted since 2009.
Restricted Stock Units (RSUs)
Under the LTIP, PSEG has granted restricted stock unitRSU awards to officers and other key employees. These awards, which are bookkeeping entries only, are subject to risk of forfeiture until vested by continued employment. Until distributed, the units are credited with dividend equivalentsequivalent units (DEUs) proportionate to the dividends paid on PSEG common stock. Distributions are made in shares of common stock. The restricted stock unitRSU grants for 20172020 and 20162019 generally vest at the end of three years. Vesting may be accelerated (pro-rated basis or full vesting) upon certain events such as change-in-control, retirement, disability change-in-control or death.
Performance Share Units (PSUs)
Under the LTIP, PSEG has granted performance share unitsPSUs to officers and other key employees. These provide for paymentdistribution in shares of PSEG common stock based on achievement of certain financial goals over a three-yearthree-year performance period. Following the end of the performance period, the payout varies from 0% to 200% of the number of performance unitsPSUs granted depending on PSEG’s performance with respect to certain financial targets, including targets related to comparative performance against other companies in a peer group of energy companies. The performance share unitsPSUs are credited with dividend equivalentsDEUs proportionate to the dividends paid on PSEG common stock. Distributions are made in shares of common stock. Vesting may be accelerated on a pro-rated basis for the period of the employee’s service during the performance period as a result of certain events, such as change-in-control, (unless substituted with an equity award of equal value), retirement, death or disability.

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Stock-Based Compensation
PSEG recognizes compensation expense for stock options based on their grant date fair values, which are determined using the Black-Scholes option-pricing model. Stock option awards are expensed on a tranche-specific basis over the requisite service period of the award. Ultimately, compensation expense for stock options is recognized for awards that vest.
PSEG recognizes compensation expense for restricted stock unitsRSUs over the vesting period based on the grant date fair value of the shares, which is equal to the closing market price of PSEG’s common stock on the date of the grant.
PSEG recognizes compensation expense for the total shareholder return (TSR) target for its performance share unitPSU awards based on the grant date fair values of the award, which are determined using the Monte Carlo model. The following table provides the assumptions used to calculate the grant date fair value of the TSR portion of the PSU awards for 2020, 2019 and 2018:
Grant Date Risk-Free Interest RateVolatility
February 18, 20201.36%15.00%
February 19, 20192.47%16.74%
February 20, 20182.36%17.57%
The accrual of compensation cost is based on the probable achievement of the performance conditions, which result in a payout from 0% to 200% of the initial grant. PSEG recognizes compensation expense for the return on invested capital target for its performance share unitsPSUs based on the grant date fair value of the awards, which is equal to the market price of PSEG’s common stock on the date of the grant. The accrual during the year of grant is estimated at 100% of the original grant. Such accrual may be adjusted to reflect the actual outcome.
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   2017 2016 2015 
   Millions 
 Compensation Cost included in Operation and Maintenance Expense $31
 $29
 $34
 
 Income Tax Benefit Recognized in Consolidated Statement of Operations $13
 $12
 $14
 
         
202020192018
Millions
Compensation Cost included in O&M Expense$35 $33 $30 
Income Tax Benefit Recognized in Consolidated Statement of Operations$10 $9 $9 
For 2017, 20162020, 2019 and 2015 the2018, PSEG also recorded excess tax benefitbenefits of $4$2 million, $4$5 million and $3 million, respectively was included as financing cash flows on the Consolidated Statements of Cash Flow.respectively.
PSEG recognizes compensation cost of awards issued over the shorter of the original vesting period or the period beginning on the date of grant and ending on the date an individual is eligible for retirement and the award vests.
Stock Options
Changes inAs of January 1, 2019, there were 231,933 stock options for 2017 are summarized as follows:
           
   Options Weighted Average Exercise Price Weighted Average Remaining Years Contractual Term Aggregate Intrinsic Value 
 Outstanding as of January 1, 2017 1,029,900
 $37.93
     
 Exercised 654,200
 $40.02
     
 Canceled/Forfeited 27,800
 $44.44
     
 Outstanding as of December 31, 2017 347,900
 $33.49
 1.9 $6,265,679
 
 Exercisable at December 31, 2017 347,900
 $33.49
 1.9 $6,265,679
 
           
The fair valueoutstanding, all of each option grant is estimated on the datewhich were exercised in 2019 at a weighted average price of grant using the Black-Scholes option-pricing model.$33.49. There were no option grantsstock options granted or vested in 2017, 20162020, 2019 and 2015.2018.
Activity for options exercised for the years ended December 31, 2017, 20162020, 2019 and 20152018 is shown below:
202020192018
 Millions
Total Intrinsic Value of Options Exercised$0 $5 $2 
Cash Received from Options Exercised$0 $8 $4 
Tax Benefit Realized from Options Exercised$0 $1 $0 
         
   2017 2016 2015 
   Millions 
 Total Intrinsic Value of Options Exercised $5
 $7
 $3
 
 Cash Received from Options Exercised $26
 $22
 $12
 
 Tax Benefit Realized from Options Exercised $—
 $1
 $—
 
         
No options were vested during the years ended December 31, 2017, 2016 and 2015.

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Restricted Stock UnitsRSUs
Changes in restricted stock unitsRSUs for the year ended December 31, 20172020 are summarized as follows:
SharesWeighted
Average Grant
Date Fair Value		Weighted Average
Remaining Years
Contractual Term		Aggregate
Intrinsic Value
Non-vested as of January 1, 2020214,981 $50.41 
Granted219,749 $58.85 
Vested203,032 $55.20 
Canceled/Forfeited8,800 $54.13 
Non-vested as of December 31, 2020222,898 $54.21 0.9$12,994,953 
           
   Shares 
Weighted
Average Grant
Date Fair Value
 
Weighted Average
Remaining Years
Contractual Term
 
Aggregate
Intrinsic Value
 
 Non-vested as of January 1, 2017 322,196
 $38.75
     
 Granted 212,158
 $44.33
     
 Vested 303,092
 $39.96
     
 Canceled/Forfeited 17,363
 $41.76
     
 Non-vested as of December 31, 2017 213,899
 $42.32
 1.0 $11,015,850
 
   

       
The weighted average grant date fair value per share for restricted stockRSUs during the years ended December 31, 2017, 20162020, 2019 and 20152018 was $44.33, $42.28$58.85, $56.24 and $39.65$49.34 per share, respectively.
The total intrinsic value of restricted stock unitsRSUs distributed during the years ended December 31, 2017, 20162020, 2019 and 20152018 was
$13 $11 million, $17$16 million and $11$12 million, respectively.
As of December 31, 2017,2020, there was approximately $3$4 million of unrecognized compensation cost related to the restricted stock units,RSUs, which is expected to be recognized over a weighted average period of ten months. Dividend equivalents units0.9 years. DEUs of 30,06625,920 accrued on the restricted stock unitsRSUs during the year.
Performance Share UnitsPSUs
Changes in performance share unitsPSUs for the year ended December 31, 20172020 are summarized as follows:
SharesWeighted
Average Grant
Date Fair Value		Weighted Average
Remaining Years
Contractual Term		Aggregate
Intrinsic Value
Non-vested as of January 1, 2020334,515 $59.30 
Granted447,815 $51.79 
Vested285,977 $54.96 
Canceled/Forfeited20,512 $58.37 
Non-vested as of December 31, 2020475,841 $54.88 1.7$27,741,530 
           
   Shares 
Weighted
Average
Grant Date
Fair Value
 
Weighted Average
Remaining Years
Contractual Term
 
Aggregate
Intrinsic Value
 
 Non-vested as of January 1, 2017 393,812
 $44.20
     
 Granted 382,830
 $45.02
     
 Vested 402,451
 $44.03
     
 Canceled/Forfeited 41,730
 $44.69
     
 Non-vested as of December 31, 2017 332,461
 $45.29
 1.7 $17,121,742
 
           
The weighted average grant date fair value per share for performance share unitsPSUs during the years ended December 31, 2017, 20162020, 2019 and 20152018 was $45.02, $45.97$51.79, $62.17 and $41.32$54.95 per share, respectively.
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The total intrinsic value of performance share unitsPSUs distributed during the years ended December 31, 2017, 20162020, 2019 and 20152018 was
$18 $19 million, $17 million and $13$17 million, respectively.
As of December 31, 2017,2020, there was approximately $16$24 million of unrecognized compensation cost related to the performance share units,PSUs, which is expected to be recognized over a weighted average period of one year. Dividend equivalents units1.7 years. DEUs of 38,42542,925 accrued on the performance share unitsPSUs during the year.
Outside Directors
Under the Directors Equity Plan, annually, on the first business day of May, each non-employee member of the Board of Directors is awarded stock units based on the amount of annual compensation to be paid at the closing price of PSEG common stock on that date. Dividend equivalentsDEUs are credited quarterly and distributions will commence upon the director leaving the Boardoccur as specified by him/hertheir election in accordance with the provisions of the Directors Equity Plan.
The fair value of these awards is recorded as compensation expense in the Consolidated Statements of Operations. Compensation expense for the plan was immaterial for each of the years ended December 31, 2017, 20162020, 2019 and 2015.2018.
Employee Stock Purchase Plan (ESPP)ESPP
PSEG maintains an ESPP for all eligible employees of PSEG and its subsidiaries. Under the ESPP, shares of PSEG common stock may be purchased at 95% of the fair market value for represented employees and 90% for non-represented employees through payroll deductions. Dividends willare to be reinvested for all employees at 95% of the fair market pricepaid out in cash unless the participant elects the dividends to receive a cash dividend.be reinvested at fair market price. All employees are required to hold the shares purchased under the ESPP for at least three

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months from the purchase date. In any year, employees may purchase shares having a value not exceeding 10% of their base pay. Compensation expense recognized under this program was immaterial$1 million for each of the years ended December 31, 2017, 20162020 and 2015.2019 and immaterial for the year ended December 31, 2018.
During the years ended December 31, 2017, 20162020, 2019 and 2015,2018, employees purchased 288,527373,682 shares, 262,763280,077 shares and 250,499286,559 shares, respectively, at an average price of $42.07, $40.70$47.26, $54.67 and $36.66$47.44 per share, respectively. As of December 31, 2017, 3.22020, 2.2 million shares were available for future issuance under this plan.

Note 19. Other Income and Deductions
161
           
 Other Income PSE&G Power Other (A) 
Consolidated
Total
 
   Millions 
 Year Ended December 31, 2017         
 NDT Fund Gains, Interest, Dividend and Other Income $—
 $202
 $—
 $202
 
 Allowance for Funds Used During Construction 56
 —
 —
 56
 
 Rabbi Trust Realized Gains, Interest and Dividends 5
 6
 13
 24
 
 Solar Loan Interest 21
 —
 —
 21
 
 Other 10
 5
 1
 16
 
 Total Other Income $92
 $213
 $14
 $319
 
 Year Ended December 31, 2016         
 NDT Fund Gains, Interest, Dividend and Other Income $—
 $96
 $—
 $96
 
 Allowance for Funds Used During Construction 49
 —
 —
 49
 
 Rabbi Trust Realized Gains, Interest and Dividends 3
 3
 6
 12
 
 Solar Loan Interest 22
 —
 —
 22
 
 Other 9
 3
 —
 12
 
 Total Other Income $83
 $102
 $6
 $191
 
 Year Ended December 31, 2015         
 NDT Fund Gains, Interest, Dividend and Other Income $—
 $138
 $—
 $138
 
 Allowance for Funds Used During Construction 48
 —
 —
 48
 
 Rabbi Trust Realized Gains, Interest and Dividends 2
 2
 6
 10
 
 Solar Loan Interest 23
 —
 —
 23
 
 Gain on Insurance Recovery —
 28
 —
 28
 
 Other 6
 1
 —
 7
 
 Total Other Income $79
 $169
 $6
 $254
 
           
           
 Other Deductions PSE&G Power Other (A) 
Consolidated
Total
 
   Millions 
 Year Ended December 31, 2017         
 NDT Fund Realized Losses and Expenses $—
 $32
 $—
 $32
 
 Other 5
 24
 30
 59
 
 Total Other Deductions $5
 $56
 $30
 $91
 
 Year Ended December 31, 2016         
 NDT Fund Realized Losses and Expenses $—
 $40
 $—
 $40
 
 Other 4
 17
 6
 27
 
 Total Other Deductions $4
 $57
 $6
 $67
 
 Year Ended December 31, 2015         
 NDT Fund Realized Losses and Expenses $—
 $45
 $—
 $45
 
 Other 4
 27
 26
 57
 
 Total Other Deductions $4
 $72
 $26
 $102
 
           
(A)
Other consists of activity at PSEG (as parent company), Energy Holdings, Services, PSEG LI and intercompany eliminations.

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Note 20.21. Other Income (Deductions)
PSE&GPSEG PowerOther (A)Consolidated
Total
Millions
Year Ended December 31, 2020
NDT Fund Interest and Dividends$0 $52 $0 $52 
Allowance for Funds Used During Construction87 0 0 87 
Solar Loan Interest15 0 0 15 
Donations0 0 (3)(3)
Purchase of Tax Losses under New Jersey Technology Tax Benefit Transfer Program0 (36)0 (36)
Other6 (4)(2)0 
Total Other Income (Deductions)$108 $12 $(5)$115 
Year Ended December 31, 2019
NDT Fund Interest and Dividends$0 $57 $0 $57 
Allowance for Funds Used During Construction59 0 0 59 
Solar Loan Interest16 0 0 16 
Donations0 0 (11)(11)
Other8 (3)(1)4 
Total Other Income (Deductions)$83 $54 $(12)$125 
Year Ended December 31, 2018
NDT Fund Interest and Dividends$0 $52 $0 $52 
Allowance for Funds Used During Construction54 0 0 54 
Solar Loan Interest18 0 0 18 
Donations0 0 (17)(17)
Purchase of Tax Losses under New Jersey Technology Tax Benefit Transfer Program0 (26)0 (26)
Other8 (5)1 4 
Total Other Income (Deductions)$80 $21 $(16)$85 

(A)Other consists of activity at PSEG (as parent company), Energy Holdings, Services, PSEG LI and intercompany eliminations.
162

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 22. Income Taxes
A reconciliation of reported income tax expense for PSEG with the amount computed by multiplying pre-tax income by the statutory federal income tax rate of 35%21% is as follows:
         
   Years Ended December 31, 
 PSEG 2017 2016 2015 
   Millions 
 Net Income $1,574
 $887
 $1,679
 
 Income Taxes:       
 Operating Income:       
 Current Expense (Benefit):       
 Federal $86
 $(74) $243
 
 State (31) 61
 85
 
 Total Current 55
 (13) 328
 
 Deferred (Benefit) Expense:       
 Federal (482) 311
 540
 
 State 92
 28
 104
 
 Total Deferred (390) 339
 644
 
 Investment Tax Credit (ITC) 29
 85
 29
 
 Total Income Tax (Benefit) Expense $(306) $411
 $1,001
 
 Pre-Tax Income $1,268
 $1,298
 $2,680
 
 Tax Computed at Statutory Rate @ 35% $444
 $454
 $938
 
 Increase (Decrease) Attributable to Flow-Through of Certain Tax Adjustments:       
 State Income Taxes (net of federal income tax) 36
 56
 129
 
 Uncertain Tax Positions (3) (31) 7
 
 Manufacturing Deduction (13) (17) (10) 
 NDT Fund 19
 3
 7
 
 Plant-Related Items (23) (20) (20) 
 Tax Credits (22) (25) (13) 
 Audit Settlement 6
 —
 —
 
 Nuclear Decommissioning Tax Carryback —
 —
 (33) 
 Provisional Deferred Tax Benefit - Tax Act (755) —
 —
 
 Other 5
 (9) (4) 
 Sub-Total (750) (43) 63
 
 Total Income Tax (Benefit) Expense $(306) $411
 $1,001
 
 Effective Income Tax Rate (24.1)% 31.7% 37.4% 
         
 Years Ended December 31,
PSEG202020192018
 Millions
Net Income$1,905 $1,693 $1,438 
Income Taxes:
Operating Income:
Current (Benefit) Expense:
Federal$385 $84 $(97)
State48 18 83 
Total Current433 102 (14)
Deferred Expense (Benefit):
Federal(164)3 373 
State141 132 71 
Total Deferred(23)135 444 
ITC(14)20 (13)
Total Income Tax Expense (Benefit)$396 $257 $417 
Pre-Tax Income$2,301 $1,950 $1,855 
Tax Computed at Statutory Rate @ 21%$483 $410 $390 
Increase (Decrease) Attributable to Flow-Through of Certain Tax Adjustments:
State Income Taxes (net of federal income tax)147 117 123 
Uncertain Tax Positions3 0 (24)
NDT Fund32 34 (13)
Plant-Related Items(9)(2)(10)
Tax Credits(18)(18)(16)
Audit Settlement(27)0 0 
Leasing Activities(35)0 0 
Tax Adjustment Credit(205)(272)(30)
Deferred Tax Expense (Benefit) - Tax Act0 0 3 
Bad Debt Flow-Through28 0 0 
Other(3)(12)(6)
Subtotal(87)(153)27 
Total Income Tax Expense (Benefit)$396 $257 $417 
Effective Income Tax Rate17.2 %13.2 %22.5 %


 

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The following is an analysis of deferred income taxes for PSEG:
       
   As of December 31, 
 PSEG 2017 2016 
   Millions 
 Deferred Income Taxes     
 Assets:     
 Noncurrent     
 Regulatory Liability Excess Deferred Tax $602
 $—
 
 OPEB 217
 283
 
 Related to Uncertain Tax Position 142
 155
 
 Total Noncurrent Assets $961
 $438
 
       
 Liabilities:     
 Noncurrent:     
 Plant-Related Items $4,257
 $6,593
 
 New Jersey Corporate Business Tax 674
 674
 
 Leasing Activities 384
 565
 
 AROs and NDT Fund 233
 398
 
 Pension Costs 123
 197
 
 Taxes Recoverable Through Future Rates (net) 80
 208
 
 Other 171
 212
 
 Total Noncurrent Liabilities $5,922
 $8,847
 
 Summary of Accumulated Deferred Income Taxes:     
 Net Noncurrent Deferred Income Tax Liabilities $4,961
 $8,409
 
 ITC 279
 249
 
 Net Total Noncurrent Deferred Income Taxes and ITC $5,240
 $8,658
 
       
The deferred tax effect of certain assets and liabilities is presented in the table above net of the deferred tax effect associated with the respective regulatory deferrals. Also, the deferred tax effect of AROs is presented net of the deferred tax effect of the associated funding of those obligations.
In December 2017, new tax legislation was enacted, reducing the statutory U.S. corporate income tax rate from a maximum of 35% to 21%, effective January 1, 2018. PSEG is subject to ASC 740, which requires that the effect on deferred tax assets and liabilities of a change in tax rates be recognized in the period the tax rate was enacted. The impact of the reduced tax rate is the primary reason for the decrease in the deferred tax liabilities.




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A reconciliation of reported income tax expense for PSE&G with the amount computed by multiplying pre-tax income by the statutory federal income tax rate of 35% is as follows:
         
   Years Ended December 31, 
 PSE&G 2017 2016 2015 
   Millions 
 Net Income $973
 $889
 $787
 
 Income Taxes:       
 Operating Income:       
 Current (Benefit) Expense:       
 Federal $(52) $(153) $32
 
 State (1) 10
 52
 
 Total Current (53) (143) 84
 
 Deferred Expense:       
 Federal 492
 551
 325
 
 State 129
 102
 52
 
 Total Deferred 621
 653
 377
 
 ITC (5) 5
 9
 
 Total Income Tax Expense $563
 $515
 $470
 
 Pre-Tax Income $1,536
 $1,404
 $1,257
 
 Tax Computed at Statutory Rate @ 35% $538
 $491
 $440
 
 Increase (Decrease) Attributable to Flow-Through of Certain Tax Adjustments:       
 State Income Taxes (net of federal income tax) 83
 72
 67
 
 Uncertain Tax Positions (9) (18) (14) 
 Plant-Related Items (23) (20) (20) 
 Tax Credits (9) (7) (6) 
 Provisional Deferred Tax Benefit - Tax Act (10) —
 —
 
 Other (7) (3) 3
 
 Sub-Total 25
 24
 30
 
 Total Income Tax Expense $563
 $515
 $470
 
 Effective Income Tax Rate 36.7% 36.7% 37.4% 
         















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The following is an analysis of deferred income taxes for PSE&G:
       
   As of December 31, 
 PSE&G 2017 2016 
   Millions 
 Deferred Income Taxes     
 Assets:     
 Noncurrent:     
      Regulatory Liability Excess Deferred Tax $602
 $—
 
 OPEB 116
 189
 
 Total Noncurrent Assets $718
 $189
 
 Liabilities:     
 Noncurrent:     
 Plant-Related Items $3,311
 $4,983
 
 New Jersey Corporate Business Tax 378
 385
 
 Pension Costs 152
 252
 
 Conservation Costs 24
 33
 
 Taxes Recoverable Through Future Rates (net) 80
 208
 
 Other 86
 118
 
 Total Noncurrent Liabilities $4,031
 $5,979
 
 Summary of Accumulated Deferred Income Taxes:     
 Net Noncurrent Deferred Income Tax Liabilities $3,313
 $5,790
 
 ITC 78
 83
 
 Net Total Noncurrent Deferred Income Taxes and ITC $3,391
 $5,873
 
       
As of December 31,
PSEG20202019
 Millions
Deferred Income Taxes
Assets:
Noncurrent:
Regulatory Liability Excess Deferred Tax$485 $539 
OPEB135 151 
Related to Uncertain Tax Positions29 97 
Interest Disallowance Carry Forward39 76 
Operating Leases60 64 
Other170 128 
Total Noncurrent Assets$918 $1,055 
Liabilities:
Noncurrent:
Plant-Related Items$5,163 $5,051 
New Jersey Corporate Business Tax1,016 876 
Leasing Activities133 284 
AROs and NDT Fund324 277 
Taxes Recoverable Through Future Rates (net)114 108 
Pension Costs97 98 
Operating Leases55 59 
Other247 273 
Total Noncurrent Liabilities$7,149 $7,026 
Summary of Accumulated Deferred Income Taxes:
Net Noncurrent Deferred Income Tax Liabilities$6,231 $5,971 
ITC271 285 
Net Total Noncurrent Deferred Income Taxes and ITC$6,502 $6,256 
The deferred tax effect of certain assets and liabilities is presented in the table above net of the deferred tax effect associated with the respective regulatory deferrals.
In December 2017, new tax legislation was enacted, reducing the statutory U.S. corporate income tax rate from a maximum of 35% to 21%, effective January 1, 2018. PSE&G is subject to ASC 740, which requires that the effect on deferred tax assets and liabilities of a change in tax rates be recognized in the period the tax rate was enacted. The impact of the reduced tax rate is the primary reason for the decrease in the deferred tax liabilities.









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A reconciliation of reported income tax expense for PSE&G with the amount computed by multiplying pre-tax income by the statutory federal income tax rate of 21% is as follows:
 Years Ended December 31,
PSE&G202020192018
 Millions
Net Income$1,327 $1,250 $1,067 
Income Taxes:
Operating Income:
Current (Benefit) Expense:
Federal$179 $121 $(62)
State8 0 1 
Total Current187 121 (61)
Deferred Expense (Benefit):
Federal(71)(156)287 
State128 117 122 
Total Deferred57 (39)409 
ITC(4)11 (4)
Total Income Tax Expense$240 $93 $344 
Pre-Tax Income$1,567 $1,343 $1,411 
Tax Computed at Statutory Rate @ 21%$329 $282 $296 
Increase (Decrease) Attributable to Flow-Through of Certain Tax Adjustments:
State Income Taxes (net of federal income tax)106 92 98 
Uncertain Tax Positions4 1 (1)
Plant-Related Items(9)(2)(10)
Tax Credits(9)(8)(8)
Audit Settlement(2)0 0 
Tax Adjustment Credit(205)(272)(30)
Bad Debt Flow-Through28 0 0 
Other(2)0 (1)
Subtotal(89)(189)48 
Total Income Tax Expense$240 $93 $344 
Effective Income Tax Rate15.3 %6.9 %24.4 %












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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


The following is an analysis of deferred income taxes for PSE&G:
As of December 31,
PSE&G20202019
 Millions
Deferred Income Taxes
Assets:
Noncurrent:
     Regulatory Liability Excess Deferred Tax$485 $539 
OPEB82 97 
     Related to Uncertain Tax Positions0 42 
Operating Leases21 21 
Other92 55 
Total Noncurrent Assets$680 $754 
Liabilities:
Noncurrent:
Plant-Related Items$3,874 $3,754 
New Jersey Corporate Business Tax721 588 
Pension Costs166 160 
Taxes Recoverable Through Future Rates (net)114 108 
Conservation Costs61 44 
Operating Leases21 21 
Related to Uncertain Tax Positions5 0 
Other161 183 
Total Noncurrent Liabilities$5,123 $4,858 
Summary of Accumulated Deferred Income Taxes:
Net Noncurrent Deferred Income Tax Liabilities$4,443 $4,104 
ITC81 85 
Net Total Noncurrent Deferred Income Taxes and ITC$4,524 $4,189 
The deferred tax effect of certain assets and liabilities is presented in the table above net of the deferred tax effect associated with the respective regulatory deferrals.






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A reconciliation of reported income tax expense for PSEG Power with the amount computed by multiplying pre-tax income by the statutory federal income tax rate of 35%21% is as follows:
 Years Ended December 31,
PSEG Power202020192018
 Millions
Net Income$594 $468 $365 
Income Taxes:
Operating Income:
Current (Benefit) Expense:
Federal$135 $(48)$(164)
State(7)3 24 
Total Current128 (45)(140)
Deferred Expense (Benefit):
Federal39 208 214 
State31 31 1 
Total Deferred70 239 215 
ITC(10)9 (9)
Total Income Tax Expense (Benefit)$188 $203 $66 
Pre-Tax Income$782 $671 $431 
Tax Computed at Statutory Rate @ 21%$164 $141 $91 
Increase (Decrease) Attributable to Flow-Through of Certain Tax Adjustments:
State Income Taxes (net of federal income tax)18 25 21 
NDT Fund32 34 (13)
Tax Credits(9)(10)(7)
Uncertain Tax Positions5 11 (24)
Audit Settlement(21)0 0 
Deferred Tax Benefit - Tax Act0 0 (1)
Other(1)2 (1)
Subtotal24 62 (25)
Total Income Tax Expense (Benefit)$188 $203 $66 
Effective Income Tax Rate24.0 %30.3 %15.3 %
         
   Years Ended December 31, 
 Power 2017 2016 2015 
   Millions 
 Net Income $479
 $18
 $856
 
 Income Taxes:       
 Operating Income:       
 Current Expense (Benefit):       
 Federal $95
 $107
 $220
 
 State (17) 40
 30
 
 Total Current 78
 147
 250
 
 Deferred (Benefit) Expense:       
 Federal (804) (222) 189
 
 State (37) (68) 52
 
 Total Deferred (841) (290) 241
 
 ITC 34
 82
 20
 
 Total Income Tax (Benefit) Expense $(729) $(61) $511
 
 Pre-Tax (Loss) Income $(250) $(43) $1,367
 
 Tax Computed at Statutory Rate @ 35% $(88) $(15) $478
 
 Increase (Decrease) Attributable to Flow-Through of Certain Tax Adjustments:       
 State Income Taxes (net of federal income tax) (36) (18) 59
 
 Manufacturing Deduction (13) (17) (10) 
 NDT Fund 19
 3
 7
 
 Tax Credits (12) (18) (7) 
 Uncertain Tax Positions 7
 9
 22
 
 Audit Settlement 1
 —
 —
 
 Nuclear Decommissioning Tax Carryback —
 —
 (33) 
 Provisional Deferred Tax Benefit - Tax Act (610) —
 —
 
 Other 3
 (5) (5) 
 Sub-Total (641) (46) 33
 
 Total Income Tax (Benefit) Expense $(729) $(61) $511
 
 Effective Income Tax Rate 291.6% 141.9% 37.4% 
         



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The following is an analysis of deferred income taxes for PSEG Power:
       
   As of December 31, 
 Power 2017 2016 
   Millions 
 Deferred Income Taxes     
 Assets:     
 Noncurrent:     
 Related to Uncertain Tax Positions $45
 $53
 
 Pension Costs 40
 68
 
 Contractual Liabilities & Environmental Costs 12
 18
 
 Other 93
 76
 
 Total Noncurrent Assets $190
 $215
 
 Liabilities:     
 Noncurrent:     
 Plant-Related Items $935
 $1,605
 
 AROs and NDT Fund 235
 400
 
 New Jersey Corporate Business Tax 225
 214
 
 Total Noncurrent Liabilities $1,395
 $2,219
 
 Summary of Accumulated Deferred Income Taxes:     
 Net Noncurrent Deferred Income Tax Liabilities $1,205
 $2,004
 
 ITC 201
 166
 
 Net Total Noncurrent Deferred Income Taxes and ITC $1,406
 $2,170
 
       
In the above table, the deferred tax effect of asset retirement obligations is presented net of the deferred tax effect of the associated funding of those obligations.
As of December 31,
PSEG Power20202019
 Millions
Deferred Income Taxes
Assets:
Noncurrent:
Related to Uncertain Tax Positions$38 $72 
Pension Costs68 61 
OPEB41 40 
Operating Leases13 15 
Interest Disallowance Carry Forward6 12 
Contractual Liabilities & Environmental Costs6 7 
Other36 30 
Total Noncurrent Assets$208 $237 
Liabilities:
Noncurrent:
Plant-Related Items$1,286 $1,292 
New Jersey Corporate Business Tax308 282 
AROs and NDT Fund325 278 
Operating Leases13 15 
Other21 45 
Total Noncurrent Liabilities$1,953 $1,912 
Summary of Accumulated Deferred Income Taxes:
Net Noncurrent Deferred Income Tax Liabilities$1,745 $1,675 
ITC191 201 
Net Total Noncurrent Deferred Income Taxes and ITC$1,936 $1,876 
PSEG, PSE&G and PSEG Power each provide deferred taxes at the enacted statutory tax rate for all temporary differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities irrespective of the treatment for rate-making purposes. Management believes that it is probable that the accumulated tax benefits that previously have been treated as a flow-through item to PSE&G customers will be recovered from or refunded to PSE&G’s customers in the future. See Note 6.7. Regulatory Assets and Liabilities.
In December 2017,Effective January 1, 2018, the U.S. government enacted comprehensive tax legislation. The Tax Act establishes newestablished tax laws that will take effect in 2018, including, but not limited to (1)among other things, the reduction of the U.S. federal corporate income tax rate from a maximum of 35% to 21%; (2) elimination of the corporate alternative minimum tax (AMT); (3), a new limitation on deductible interest, expense; (4) the repeal of the domestic production activity deduction; (5)and limitations on the deductibilityutilization of certain executive compensation; and (6) limitations on net operating losses (NOLs).
The 2018 decrease in the federal tax rate resulted in PSE&G recording excess deferred income taxes. As of December 31, 2019, the balance was approximately $1.9 billion with a Regulatory Liability of approximately $2.6 billion. In 2020, PSE&G returned approximately $286 million of excess deferred income taxes and previously realized and current period deferred income taxes related to tax repair deductions to its customers with a reduction to tax expense of approximately $205 million. The flowback to customers of the excess deferred income taxes and previously realized tax repair deductions resulted in a decrease of approximately $255 million in the Regulatory Liability. The current period tax repair deduction reduces tax expense and revenue and recognizes a Regulatory Asset as PSE&G believes it is probable that the current period tax repair deductions flowed through to the customers will be recovered from customers in the future. See Note 7. Regulatory Assets and Liabilities for additional information.
In March 2020, the federal Coronavirus Aid, Relief, and Economic Security Act (CARES Act) was enacted. Among other provisions, the CARES Act allows a five-year carryback of any NOL generated in a taxable year beginning after December 31, 2017, and before January 1, 2021.
In April 2020, the IRS issued a PLR to 80% of taxable income. In addition,PSE&G concluding that certain changes were madeexcess deferred taxes previously classified as protected should be classified as unprotected. Unprotected excess deferred income taxes are not subject to the bonus depreciationnormalization rules that will impact 2017.
The SEC staff issued Staff Accounting Bulletin 118 (SAB 118), which provides guidance on accounting for the tax effects of the Tax Act. SAB 118 provides a measurement period that should not extend beyond one year from the Tax Act enactment date for companies to complete the accounting under ASC 740. In accordance with SAB 118, a company must reflect the income tax effects of those aspects of the Tax Act for which the accounting under ASC 740 is complete. To the extent that a company’s accounting for certain income tax effects of the Tax Act is incomplete but it is able to determine a reasonable estimate, it must record a provisional estimate in the financial statements. If a company cannot determine a provisional estimate to be included in the financial statements, it should continue to apply ASC 740 on the basis of the provisions of the tax laws that were in effect immediately before the enactment of the Tax Act.
PSEG, PSE&G and Power are subject to ASC 740, which requires that the effect on deferred tax assets and liabilities of a change in tax rates be recognized in the period the tax rate change is enacted.
The majority of the current period activity was determined using the federal income tax rate of 35% and state income tax rate of 9%. As required under ASC 740, the ending 2017 deferred tax balances were adjusted to reflect the enacted lower tax rate, which resulted in a one-time, provisional deferred tax benefit of $755 million, including $610 million related to Power and $149 million related to Energy Holdings (including other impacts related to the new tax legislation, PSEG’s net non-cash provisional earnings benefit was $745 million, including $588 million related to Power and $147 million related to Energy

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Holdings).allowing them to be refunded to customers sooner as agreed to with FERC and the BPU. In addition,July 2020, FERC and the BPU approved PSE&G had&G’s requests to refund these unprotected excess deferred income taxes of approximately $2.1 billion as of December 31, 2017 and recorded a $2.9 billion revenue impactto customers. FERC approved the refund of these unprotected excess deferred income taxes aswithin the 2019 true-up filing. The BPU approved the refund of these unprotected excess deferred income taxes within the next five years beginning in July 2020. See Note 7. Regulatory Assets and Liabilities where it is probablefor additional information.
In July 2020, the IRS issued final and proposed regulations addressing the limitation on deductible business interest expense contained in the Tax Act. These regulations retroactively allow depreciation to be added back in computing the 30% adjusted taxable income (ATI) cap, increasing the amount of interest that refundscan be deducted by unregulated businesses in years before 2022. For 2022 and after, the regulations continue to disallow the addback of depreciation in the computation of ATI, effectively lowering the cap on the amount of deductible business interest and contain special rules in allocating interest between regulated and non-regulated businesses. The portion of PSEG’s and PSEG Power’s business interest expense that was disallowed in 2018 and 2019 under the previously issued proposed regulations will now be made to customersdeductible in future rates. The amount and timing of any such refund cannot be determined at this time.those respective years. These regulations remain uncertain in some respects.
For certain aspectsIn late December 2020, the Consolidated Appropriations Act (CAA), 2021 was enacted. PSEG’s initial analysis of the Tax Act, which are discussed below,CAA indicates that this legislation will not have a material impact on the financial condition and cash flows of PSEG, PSE&G and Power made reasonable, good faith estimates forPSEG Power.
We expect that a prolonged coronavirus pandemic or economic recovery may result in additional federal or state tax legislation which provisional amounts were recorded.
PSEG’s accounting for the following elements of the Tax Act is incomplete. However, PSEG was able to make reasonable, good faith estimates of certain effects and, therefore, recorded provisional adjustments for the following: the tax rules regarding the appropriate bonus deprecation rate that should be applied to assets placed in service after September 27, 2017 for Power and PSE&G, including the information required to compute the applicable depreciable tax basis, and thecan have a material impact on PSEG’s, PSE&G’s and PSEG Power’s deferred taxes associated with FIN 48 reserves.tax expense and cash tax position.
Further,Amounts recorded under the Tax Act, is unclear in certain respectsCARES Act and will require interpretationsCAA, including depreciation and implementinginterest disallowance regulations, by the Internal Revenue Service (IRS), as well as state tax authorities. The Tax Act could also beare subject to potential amendments and technical corrections whichchange based on several factors, including, among other things, whether the IRS or state taxing authorities issue additional guidance and/or further clarification. Any further guidance or clarification could impact PSEG’s, PSE&G’s and PSEG PSE&G and Power’s financial statements.
InAs of December 2015, the U.S. government enacted the Protecting Americans from31, 2020, PSE&G had a $29 million New Jersey Corporate Business Tax Hikes Act of 2015 (2015 Tax Act). Among other provisions, the 2015 Tax Act included an extension of the bonus depreciation rules and the 30% ITC for qualified property placed into service after 2016. Qualified propertyNOL that is placedexpected to be fully realized in service from January 1, 2015 through December 31, 2017 is eligible for 50% bonus depreciation. The provisions of the 2015 Tax Act have generated significant cashfuture. There are no other material tax benefits for PSEG, PSE&G and Power through tax benefits related to the accelerated depreciation. Those tax benefits would have otherwise been received over an estimated average 20 year period. However, the tax benefits have a negative impact on the rate base of several of PSE&G’s programs.
For the period beginning September 28, 2017, subject to the transition rules, the Tax Act has modified the bonus depreciation rules of the 2015 Tax Act. Subject to further guidance, it is expected that Power will be entitled to 100% expensing and bonus depreciation will no longer apply to PSE&G.carryforwards in other jurisdictions.
PSEG recorded the following amounts related to its unrecognized tax benefits, which were primarily comprised of amounts recorded for PSE&G, PSEG Power and Energy Holdings:
           
 2017 PSEG PSE&G Power 
Energy
Holdings
 
   Millions 
 Total Amount of Unrecognized Tax Benefits as of January 1, 2017 $328
 $140
 $128
 $57
 
 Increases as a Result of Positions Taken in a Prior Period 40
 15
 18
 8
 
 Decreases as a Result of Positions Taken in a Prior Period (32) (11) (10) (13) 
 Increases as a Result of Positions Taken during the Current Period 12
 5
 6
 1
 
 Decreases as a Result of Positions Taken during the Current Period (1) (1) —
 —
 
 Decreases as a Result of Settlements with Taxing Authorities —
 —
 —
 —
 
 Decreases due to Lapses of Applicable Statute of Limitations (13) (13) —
 —
 
 Total Amount of Unrecognized Tax Benefits as of December 31, 2017 $334
 $135
 $142
 $53
 
 Accumulated Deferred Income Taxes Associated with Unrecognized Tax Benefits (157) (73) (72) (12) 
 Regulatory Asset—Unrecognized Tax Benefits (56) (56) —
 —
 
 Total Amount of Unrecognized Tax Benefits that if Recognized, would Impact the Effective Tax Rate (including Interest and Penalties) $121
 $6
 $70
 $41
 
           

2020PSEGPSE&GPSEG PowerEnergy
Holdings
 Millions
Total Amount of Unrecognized Tax Benefits as of January 1, 2020$321 $124 $161 $33 
Increases as a Result of Positions Taken in a Prior Period33 21 10 1 
Decreases as a Result of Positions Taken in a Prior Period(91)(51)(36)(4)
Increases as a Result of Positions Taken during the Current Period0 0 0 0 
Decreases as a Result of Positions Taken during the Current Period0 0 0 0 
Decreases as a Result of Settlements with Taxing Authorities(116)(64)(52)0 
Decreases due to Lapses of Applicable Statute of Limitations0 0 0 0 
Total Amount of Unrecognized Tax Benefits as of December 31, 2020$147 $30 $83 $30 
Accumulated Deferred Income Taxes Associated with Unrecognized Tax Benefits(69)(12)(49)(8)
Regulatory Asset—Unrecognized Tax Benefits(15)(15)0 0 
Total Amount of Unrecognized Tax Benefits that if Recognized, would Impact the Effective Tax Rate (including Interest and Penalties)$63 $3 $34 $22 
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 2016 PSEG PSE&G Power 
Energy
Holdings
 
   Millions 
 Total Amount of Unrecognized Tax Benefits as of January 1, 2016 $386
 $181
 $111
 $93
 
 Increases as a Result of Positions Taken in a Prior Period 12
 3
 6
 2
 
 Decreases as a Result of Positions Taken in a Prior Period (62) (23) (1) (38) 
 Increases as a Result of Positions Taken during the Current Period 19
 6
 12
 —
 
 Decreases as a Result of Positions Taken during the Current Period —
 —
 —
 —
 
 Decreases as a Result of Settlements with Taxing Authorities —
 —
 —
 —
 
 Decreases due to Lapses of Applicable Statute of Limitations (27) (27) —
 —
 
 Total Amount of Unrecognized Tax Benefits as of December 31, 2016 $328
 $140
 $128
 $57
 
 Accumulated Deferred Income Taxes Associated with Unrecognized Tax Benefits (200) (106) (74) (20) 
 Regulatory Asset—Unrecognized Tax Benefits (31) (31) —
 —
 
 Total Amount of Unrecognized Tax Benefits that if Recognized, would Impact the Effective Tax Rate (including Interest and Penalties) $97
 $3
 $54
 $37
 
           
2019PSEGPSE&GPSEG PowerEnergy
Holdings
 Millions
Total Amount of Unrecognized Tax Benefits as of January 1, 2019$318 $108 $151 $54 
Increases as a Result of Positions Taken in a Prior Period17 5 8 5 
Decreases as a Result of Positions Taken in a Prior Period(37)(1)(13)(22)
Increases as a Result of Positions Taken during the Current Period27 12 15 0 
Decreases as a Result of Positions Taken during the Current Period0 0 0 0 
Decreases as a Result of Settlements with Taxing Authorities(4)0 0 (4)
Decreases due to Lapses of Applicable Statute of Limitations0 0 0 0 
Total Amount of Unrecognized Tax Benefits as of December 31, 2019$321 $124 $161 $33 
Accumulated Deferred Income Taxes Associated with Unrecognized Tax Benefits(184)(71)(105)(7)
Regulatory Asset—Unrecognized Tax Benefits(46)(46)0 0 
Total Amount of Unrecognized Tax Benefits that if Recognized, would Impact the Effective Tax Rate (including Interest and Penalties)$91 $7 $56 $26 
2018PSEGPSE&GPSEG PowerEnergy
Holdings
 Millions
Total Amount of Unrecognized Tax Benefits as of January 1, 2018$334 $135 $142 $53 
Increases as a Result of Positions Taken in a Prior Period11 4 4 3 
Decreases as a Result of Positions Taken in a Prior Period(70)(31)(37)(2)
Increases as a Result of Positions Taken during the Current Period52 3 48 0 
Decreases as a Result of Positions Taken during the Current Period(3)(3)0 0 
Decreases as a Result of Settlements with Taxing Authorities(6)0 (6)0 
Decreases due to Lapses of Applicable Statute of Limitations0 0 0 0 
Total Amount of Unrecognized Tax Benefits as of December 31, 2018$318 $108 $151 $54 
Accumulated Deferred Income Taxes Associated with Unrecognized Tax Benefits(173)(57)(104)(12)
Regulatory Asset—Unrecognized Tax Benefits(46)(46)0 0 
Total Amount of Unrecognized Tax Benefits that if Recognized, would Impact the Effective Tax Rate (including Interest and Penalties)$99 $5 $47 $42 
           
 2015 PSEG PSE&G Power 
Energy
Holdings
 
   Millions 
 Total Amount of Unrecognized Tax Benefits as of January 1, 2015 $332
 $165
 $70
 $95
 
 Increases as a Result of Positions Taken in a Prior Period 87
 55
 28
 4
 
 Decreases as a Result of Positions Taken in a Prior Period (50) (43) (6) (1) 
 Increases as a Result of Positions Taken during the Current Period 28
 5
 23
 —
 
 Decreases as a Result of Positions Taken during the Current Period (1) (1) —
 —
 
 Decreases as a Result of Settlements with Taxing Authorities (10) —
 (4) (5) 
 Decreases due to Lapses of Applicable Statute of Limitations —
 —
 —
 —
 
 Total Amount of Unrecognized Tax Benefits as of December 31, 2015 $386
 $181
 $111
 $93
 
 Accumulated Deferred Income Taxes Associated with Unrecognized Tax Benefits (264) (162) (68) (34) 
 Regulatory Asset—Unrecognized Tax Benefits (27) (27) —
 —
 
 Total Amount of Unrecognized Tax Benefits that if Recognized, would Impact the Effective Tax Rate (including Interest and Penalties) $95
 $(8) $43
 $59
 
           
In April 2020, the Joint Committee on Taxation approved PSEG’s nuclear carryback claim and federal tax returns for the years 2011 and 2012. In June 2020, the federal income tax audits for years 2011 through 2016 and the nuclear carryback claim were concluded.
PSEG and its subsidiaries include accrued interest and penalties related to uncertain tax positions required to be recorded as Income Tax Expense in the Consolidated Statements of Operations. Accumulated interest and penalties that are recorded on the Consolidated Balance Sheets on uncertain tax positions were as follows:
         
   
Accumulated Interest and Penalties
on Uncertain Tax Positions
as of December 31,
 
   2017 2016 2015 
   Millions 
 PSE&G $25
 $22
 $20
 
 Power 24
 17
 6
 
 Energy Holdings 21
 20
 40
 
 Total $70
 $59
 $66
 
         


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 Accumulated Interest and Penalties
on Uncertain Tax Positions
as of December 31,
 202020192018
 Millions
PSEG$29 $40 $43 
PSE&G$9 $16 $12 
PSEG Power$5 $12 $9 
Energy Holdings$15 $13 $22 
It is reasonably possible that total unrecognized tax benefits will significantly increase or decrease within the next twelve months due to either agreements with various taxing authorities upon audit, the expiration of the Statute of Limitations, or other pending tax matters. These potential increases or decreases are as follows:
170

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

     
 Possible (Increase)/Decrease in Total Unrecognized Tax Benefits 
Over the next
12 Months
 
   Millions 
 PSEG $69
 
 PSE&G $35
 
 Power $30
 
     
Possible (Increase)/Decrease in Total Unrecognized Tax BenefitsOver the next
12 Months
Millions
PSEG$12 
PSE&G$12 
PSEG Power$0 
A description of income tax years that remain subject to examination by material jurisdictions, where an examination has not already concluded are:
PSEGPSE&GPSEG Power
United StatesPSEGPSE&GPower
United StatesFederal2017-2019N/AN/A
FederalNew Jersey2011-20162011-20192011-2019N/AN/A
New JerseyPennsylvania2006-20162017-20192011-20162017-2019N/A
PennsylvaniaConnecticut2014-20162016-20192014-2016N/AN/A
ConnecticutMaryland20162017-2019N/AN/A
TexasNew York2008-20162017-2019N/AN/A
California2006-2016N/AN/A
New York2014-2016N/A2014-2016

New Jersey State Tax Reform
In September 2020, New Jersey enacted its State Fiscal Year 2021 Budget, which amended the temporary surtax originally enacted into law in 2018, from 1.5% to 2.5% for 2020 and 2021 and extended the 2.5% surtax to 2023. PSE&G continues to be exempt and this amendment will not have a material impact on PSEG’s and PSEG Power’s financial statements.
In July 2018, New Jersey made changes to its income tax laws, including imposing the aforementioned temporary surtax, as well as requiring corporate taxpayers to file in a combined reporting group as defined under New Jersey law starting in 2019. Both provisions include an exemption for public utilities. PSEG believes PSE&G meets the definition of a public utility and, therefore, will not be impacted by the temporary surtax or be included in the combined reporting group. PSEG anticipates New Jersey will be issuing clarifying guidance regarding combined reporting rules. Any further guidance or clarification could impact PSEG’s and PSEG Power’s financial statements.




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Note 21.23. Accumulated Other Comprehensive Income (Loss), Net of Tax
           
 PSEG Other Comprehensive Income (Loss) 
 Accumulated Other Comprehensive Income (Loss) Cash Flow Hedges Pension and OPEB Plans Available-for -Sale Securities Total 
   Millions 
 Balance as of December 31, 2014 $10
 $(411) $118
 $(283) 
 Other Comprehensive Income before Reclassifications 2
 (7) (25) (30) 
 Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) (12) 32
 (2) 18
 
 Net Current Period Other Comprehensive Income (Loss) (10) 25
 (27) (12) 
 Balance as of December 31, 2015 $—
 $(386) $91
 $(295) 
 Other Comprehensive Income before Reclassifications 2
 (45) 40
 (3) 
 Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) —
 33
 2
 35
 
 Net Current Period Other Comprehensive Income (Loss) 2
 (12) 42
 32
 
 Balance as of December 31, 2016 $2
 $(398) $133
 $(263) 
 Other Comprehensive Income before Reclassifications —
 (32) 109
 77
 
 Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) (2) 24
 (65) (43) 
 Net Current Period Other Comprehensive Income (Loss) (2) (8) 44
 34
 
 Balance as of December 31, 2017 $—
 $(406) $177
 $(229) 
           
 Power Other Comprehensive Income (Loss) 
 Accumulated Other Comprehensive Income (Loss) Cash Flow Hedges Pension and OPEB Plans Available-for -Sale Securities Total 
   Millions 
 Balance as of December 31, 2014 $11
 $(351) $112
 $(228) 
 Other Comprehensive Income before Reclassifications 1
 (4) (24) (27) 
 Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) (12) 28
 (1) 15
 
 Net Current Period Other Comprehensive Income (Loss) (11) 24
 (25) (12) 
 Balance as of December 31, 2015 $—
 $(327) $87
 $(240) 
 Other Comprehensive Income before Reclassifications —
 (42) 39
 (3) 
 Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) —
 29
 3
 32
 
 Net Current Period Other Comprehensive Income (Loss) —
 (13) 42
 29
 
 Balance as of December 31, 2016 $—
 $(340) $129
 $(211) 
 Other Comprehensive Income before Reclassifications —
 (28) 106
 78
 
 Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) —
 21
 (60) (39) 
 Net Current Period Other Comprehensive Income (Loss) —
 (7) 46
 39
 
 Balance as of December 31, 2017 $—
 $(347) $175
 $(172) 
           

PSEGOther Comprehensive Income (Loss)
Accumulated Other Comprehensive Income (Loss)Cash Flow HedgesPension and OPEB PlansAvailable-for -Sale SecuritiesTotal
Millions
Balance as of December 31, 2017$0 $(406)$177 $(229)
Cumulative Effect Adjustment to Reclassify Unrealized Net Gains on Equity Investments to Retained Earnings0 0 (176)(176)
Current Period Other Comprehensive Income (Loss)
Other Comprehensive Income (Loss) before Reclassifications(1)17 (25)(9)
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)0 29 8 37 
Net Current Period Other Comprehensive Income (Loss)(1)46 (17)28 
Net Change in Accumulated Other Comprehensive Income (Loss)(1)46 (193)(148)
Balance as of December 31, 2018$(1)$(360)$(16)$(377)
Cumulative Effect Adjustment to Reclassify Stranded Tax Effects Resulting in the Change in the Federal Corporate Income Tax to Retained Earnings0 (81)0 (81)
 Current Period Other Comprehensive Income (Loss)
Other Comprehensive Income (Loss) before Reclassifications(17)(70)49 (38)
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)3 12 (8)7 
Net Current Period Other Comprehensive Income (Loss)(14)(58)41 (31)
Net Change in Accumulated Other Comprehensive Income (Loss)(14)(139)41 (112)
Balance as of December 31, 2019$(15)$(499)$25 $(489)
Other Comprehensive Income (Loss) before Reclassifications(4)(58)51 (11)
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)10 12 (26)(4)
Net Current Period Other Comprehensive Income (Loss)6 (46)25 (15)
Balance as of December 31, 2020$(9)$(545)$50 $(504)
167
172
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


PSEG PowerOther Comprehensive Income (Loss)
Accumulated Other Comprehensive Income (Loss)Cash Flow HedgesPension and OPEB PlansAvailable-for -Sale SecuritiesTotal
Millions
Balance as of December 31, 2017$0 $(347)$175 $(172)
Cumulative Effect Adjustment to Reclassify Unrealized Net Gains on Equity Investments to Retained Earnings0 0 (175)(175)
Current Period Other Comprehensive Income (Loss)
Other Comprehensive Income (Loss) before Reclassifications0 16 (19)(3)
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)0 25 6 31 
Net Current Period Other Comprehensive Income (Loss)0 41 (13)28 
Net Change in Accumulated Other Comprehensive Income (Loss)0 41 (188)(147)
Balance as of December 31, 2018$0 $(306)$(13)$(319)
Cumulative Effect Adjustment to Reclassify Stranded Tax Effects Resulting in the Change in the Federal Corporate Income Tax to Retained Earnings0 (69)0 (69)
Current Period Other Comprehensive Income (Loss)
Other Comprehensive Income (Loss) before Reclassifications0 (55)38 (17)
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)0 10 (6)4 
Net Current Period Other Comprehensive Income (Loss)0 (45)32 (13)
Net Change in Accumulated Other Comprehensive Income (Loss)0 (114)32 (82)
Balance as of December 31, 2019$0 $(420)$19 $(401)
Other Comprehensive Income (Loss) before Reclassifications0 (48)41 (7)
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)0 9 (20)(11)
Net Current Period Other Comprehensive Income (Loss)0 (39)21 (18)
Balance as of December 31, 2020$0 $(459)$40 $(419)
173
           
           
 PSEG    Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement 
     Year Ended December 31, 2015 
 Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) Location of Pre-Tax Amount In Statement of Operations Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount 
     Millions 
 Cash Flow Hedges         
 Energy-Related Contracts Operating Revenues $20
 $(8) $12
 
   Total Cash Flow Hedges   20
 (8) 12
 
 Pension and OPEB Plans         
 Amortization of Prior Service (Cost) Credit O&M Expense 12
 (3) 9
 
    Amortization of Actuarial Loss O&M Expense (68) 27
 (41) 
    Total Pension and OPEB Plans   (56) 24
 (32) 
 Available-for-Sale Securities         
 Realized Gains Other Income 100
 (52) 48
 
 Realized Losses Other Deductions (39) 20
 (19) 
 Other-Than-Temporary Impairments (OTTI) OTTI (53) 26
 (27) 
    Total Available-for-Sale Securities   8
 (6) 2
 
 Total   $(28) $10
 $(18) 
           
 Power    Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement 
     Year Ended December 31, 2015 
 Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) Location of Pre-Tax Amount In Statement of Operations Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount 
     Millions 
 Cash Flow Hedges         
 Energy-Related Contracts Operating Revenues $20
 $(8) $12
 
   Total Cash Flow Hedges   20
 (8) 12
 
 Pension and OPEB Plans         
 Amortization of Prior Service (Cost) Credit O&M Expense 11
 (3) 8
 
    Amortization of Actuarial Loss O&M Expense (60) 24
 (36) 
    Total Pension and OPEB Plans   (49) 21
 (28) 
 Available-for-Sale Securities         
 Realized Gains Other Income 98
 (51) 47
 
 Realized Losses Other Deductions (38) 19
 (19) 
 OTTI OTTI (53) 26
 (27) 
    Total Available-for-Sale Securities   7
 (6) 1
 
 Total   $(22) $7
 $(15) 
           



168
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PSEG Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement
Year Ended December 31, 2018
Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)Location of Pre-Tax Amount in Statement of OperationsPre-Tax AmountTax (Expense) BenefitAfter-Tax Amount
 Millions
Pension and OPEB Plans
Amortization of Prior Service (Cost) CreditNon-Operating Pension and OPEB Credits (Costs)$6 $(2)$4 
    Amortization of Actuarial LossNon-Operating Pension and OPEB Credits (Costs)(47)14 (33)
   Total Pension and OPEB Plans(41)12 (29)
Available-for-Sale Securities
Realized Gains (Losses)Net Gains (Losses) on Trust Investments(13)5 (8)
   Total Available-for-Sale Securities(13)5 (8)
Total$(54)$17 $(37)
PSEG Power Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement
Year Ended December 31, 2018
Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)Location of Pre-Tax Amount in Statement of OperationsPre-Tax AmountTax (Expense) BenefitAfter-Tax Amount
 Millions
Pension and OPEB Plans
Amortization of Prior Service (Cost) CreditNon-Operating Pension and OPEB Credits (Costs)$5 $(1)$4 
    Amortization of Actuarial LossNon-Operating Pension and OPEB Credits (Costs)(40)11 (29)
   Total Pension and OPEB Plans(35)10 (25)
Available-for-Sale Securities
Realized Gains (Losses)Net Gains (Losses) on Trust Investments(11)5 (6)
   Total Available-for-Sale Securities(11)5 (6)
Total$(46)$15 $(31)

174
           
           
 PSEG    Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement 
     Year Ended December 31, 2016 
 Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) Location of Pre-Tax Amount In Statement of Operations Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount 
     Millions 
 Pension and OPEB Plans         
 Amortization of Prior Service (Cost) Credit O&M Expense $12
 $(5) $7
 
    Amortization of Actuarial Loss O&M Expense (68) 28
 (40) 
    Total Pension and OPEB Plans   (56) 23
 (33) 
 Available-for-Sale Securities         
 Realized Gains Other Income 59
 (29) 30
 
 Realized Losses Other Deductions (37) 19
 (18) 
 OTTI OTTI (28) 14
 (14) 
    Total Available-for-Sale Securities   (6) 4
 (2) 
 Total   $(62) $27
 $(35) 
           
 Power    Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement 
     Year Ended December 31, 2016 
 Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) Location of Pre-Tax Amount In Statement of Operations Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount 
     Millions 
 Pension and OPEB Plans         
 Amortization of Prior Service (Cost) Credit O&M Expense $11
 $(5) $6
 
    Amortization of Actuarial Loss O&M Expense (59) 24
 (35) 
    Total Pension and OPEB Plans   (48) 19
 (29) 
 Available-for-Sale Securities         
 Realized Gains Other Income 55
 (28) 27
 
 Realized Losses Other Deductions (33) 17
 (16) 
 OTTI OTTI (28) 14
 (14) 
    Total Available-for-Sale Securities   (6) 3
 (3) 
 Total   $(54) $22
 $(32) 
           

169
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PSEG Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement
Year Ended December 31, 2019
Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)Location of Pre-Tax Amount in Statement of OperationsPre-Tax AmountTax (Expense) BenefitAfter-Tax Amount
 Millions
Cash Flow Hedges
Interest Rate SwapsInterest Expense$(4)$1 $(3)
  Total Cash Flow Hedges(4)1 (3)
Pension and OPEB Plans
Amortization of Prior Service (Cost) CreditNon-Operating Pension and OPEB Credits (Costs)26 (7)19 
    Amortization of Actuarial LossNon-Operating Pension and OPEB Credits (Costs)(43)12 (31)
   Total Pension and OPEB Plans(17)5 (12)
Available-for-Sale Securities
Realized Gains (Losses)Net Gains (Losses) on Trust Investments13 (5)8 
   Total Available-for-Sale Securities13 (5)8 
Total$(8)$1 $(7)
PSEG Power Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement
Year Ended December 31, 2019
Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)Location of Pre-Tax Amount in Statement of OperationsPre-Tax AmountTax (Expense) BenefitAfter-Tax Amount
 Millions
Pension and OPEB Plans
Amortization of Prior Service (Cost) CreditNon-Operating Pension and OPEB Credits (Costs)$23 $(7)$16 
    Amortization of Actuarial LossNon-Operating Pension and OPEB Credits (Costs)(36)10 (26)
   Total Pension and OPEB Plans(13)3 (10)
Available-for-Sale Securities
Realized Gains (Losses)Net Gains (Losses) on Trust Investments10 (4)6 
   Total Available-for-Sale Securities10 (4)6 
Total$(3)$(1)$(4)
175
           
           
 PSEG    Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement 
     Year Ended December 31, 2017 
 Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) Location of Pre-Tax Amount In Statement of Operations Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount 
     Millions 
 Cash Flow Hedges         
 Interest Rate Swaps Interest Expense 3
 (1) 2
 
   Total Cash Flow Hedges   3
 (1) 2
 
 Pension and OPEB Plans         
 Amortization of Prior Service (Cost) Credit O&M Expense $10
 $(4) $6
 
    Amortization of Actuarial Loss O&M Expense (51) 21
 (30) 
    Total Pension and OPEB Plans   (41) 17
 (24) 
 Available-for-Sale Securities         
 Realized Gains Other Income 174
 (89) 85
 
 Realized Losses Other Deductions (28) 14
 (14) 
 OTTI OTTI (12) 6
 (6) 
    Total Available-for-Sale Securities   134
 (69) 65
 
 Total   $96
 $(53) $43
 
           
 Power    Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement 
     Year Ended December 31, 2017 
 Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) Location of Pre-Tax Amount In Statement of Operations Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount 
     Millions 
 Pension and OPEB Plans         
 Amortization of Prior Service (Cost) Credit O&M Expense $9
 $(4) $5
 
    Amortization of Actuarial Loss O&M Expense (44) 18
 (26) 
    Total Pension and OPEB Plans   (35) 14
 (21) 
 Available-for-Sale Securities         
 Realized Gains Other Income 161
 (83) 78
 
 Realized Losses Other Deductions (24) 12
 (12) 
 OTTI OTTI (12) 6
 (6) 
    Total Available-for-Sale Securities   125
 (65) 60
 
 Total   $90
 $(51) $39
 
           


170
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PSEG Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement
Year Ended December 31, 2020
Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)Location of Pre-Tax Amount in Statement of OperationsPre-Tax AmountTax (Expense) BenefitAfter-Tax Amount
 Millions
Cash Flow Hedges
Interest Rate SwapsInterest Expense$(14)$4 $(10)
  Total Cash Flow Hedges(14)4 (10)
Pension and OPEB Plans
Amortization of Prior Service (Cost) CreditNon-Operating Pension and OPEB Credits (Costs)24 (7)17 
    Amortization of Actuarial LossNon-Operating Pension and OPEB Credits (Costs)(40)11 (29)
   Total Pension and OPEB Plans(16)4 (12)
Available-for-Sale Securities
Realized Gains (Losses) and ImpairmentsNet Gains (Losses) on Trust Investments42 (16)26 
   Total Available-for-Sale Securities42 (16)26 
Total$12 $(8)$4 
PSEG Power Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement
Year Ended December 31, 2020
Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)Location of Pre-Tax Amount in Statement of OperationsPre-Tax AmountTax (Expense) BenefitAfter-Tax Amount
 Millions
Pension and OPEB Plans
Amortization of Prior Service (Cost) CreditNon-Operating Pension and OPEB Credits (Costs)$21 $(6)$15 
    Amortization of Actuarial LossNon-Operating Pension and OPEB Credits (Costs)(34)10 (24)
   Total Pension and OPEB Plans(13)4 (9)
Available-for-Sale Securities
Realized Gains (Losses) and ImpairmentsNet Gains (Losses) on Trust Investments34 (14)20 
   Total Available-for-Sale Securities34 (14)20 
Total$21 $(10)$11 

176

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 22.24. Earnings Per Share (EPS) and Dividends
EPS
Diluted EPS is calculated by dividing Net Income by the weighted average number of shares of common stock outstanding, including shares issuable upon exercise of stock options outstanding or vesting of restricted stock awards granted under PSEG’s stock compensation plans and upon payment of performance unitsPSUs or restricted stock units.RSUs. For additional information on PSEG’s stock compensation plans see Note 18.20. Stock Based Compensation. The following table shows the effect of these stock options, performance unitsPSUs and restricted stock unitsRSUs on the weighted average number of shares outstanding used in calculating diluted EPS:
               
   Years Ended December 31, 
   2017 2016 2015 
   Basic Diluted Basic Diluted Basic Diluted 
 EPS Numerator:             
 (Millions)             
 Net Income $1,574
 $1,574
 $887
 $887
 $1,679
 $1,679
 
 EPS Denominator:             
 (Millions)             
 Weighted Average Common Shares Outstanding 505
 505
 505
 505
 505
 505
 
 Effect of Stock Based Compensation Awards —
 2
 —
 3
 —
 3
 
 Total Shares 505
 507
 505
 508
 505
 508
 
 EPS:             
 Net Income $3.12
 $3.10
 $1.76
 $1.75
 $3.32
 $3.30
 
               
There were approximately 0.4 million and 0.5 million stock options excluded from the weighted average common shares used for diluted EPS due to their antidilutive effect for the years ended December 31, 2016 and 2015, respectively.
 Years Ended December 31,
 202020192018
 BasicDilutedBasicDilutedBasicDiluted
EPS Numerator:
(Millions)
Net Income$1,905 $1,905 $1,693 $1,693 $1,438 $1,438 
EPS Denominator:
(Millions)
Weighted Average Common Shares Outstanding504 504 504 504 504 504 
Effect of Stock Based Compensation Awards0 3 0 3 0 3 
Total Shares504 507 504 507 504 507 
EPS:
Net Income$3.78 $3.76 $3.35 $3.33 $2.85 $2.83 
For additional information on all the types of long-term incentive awards, see Note 18.20. Stock Based Compensation.
Dividends
         
   Years Ended December 31, 
 Dividend Payments on Common Stock 2017 2016 2015 
 Per Share $1.72
 $1.64
 $1.56
 
 in Millions $870
 $830
 $789
 
         
 Years Ended December 31,
Dividend Payments on Common Stock202020192018
Per Share$1.96 $1.88 $1.80 
in Millions$991 $950 $910 
On February 20, 2018,16, 2021, PSEG’s Board of Directors approved a $0.45$0.51 per share common stock dividend for the first quarter of 2018.

2021.
171
177
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS



Note 23.25. Financial Information by Business Segment
Basis of Organization
PSEG’s, PSE&G’s and PSEG Power’s operating segments were determined by management in accordance with GAAP. These segments were determined based on how management measures performance based on segment Net Income, as illustrated in the following table, and how resources are allocated to each business. PSEG’s reportable segments are PSE&G and PSEG Power. PSE&G and PSEG Power each represent a single reportable segment and therefore no separate segment information is provided for these Registrants.
PSE&G
PSE&G earns revenues from its tariffs, under which it provides electric transmission and electric and gas distribution services to residential, commercial and industrial customers in New Jersey. The rates charged for electric transmission are regulated by FERC while the rates charged for electric and gas distribution are regulated by the BPU. Revenues are also earned from several other activities such as solar investments, sundry sales, the appliance service business, wholesale transmission services and other miscellaneous services.
PSEG Power
PSEG Power earns revenues by selling energy, capacity and ancillary services on a wholesale basis under contract to power marketers and to load servingload-serving entities and by bidding energy, capacity and ancillary services into the markets for these products. A significant portion of PSEG Power’s revenue is obtained from the various ISOs in which PSEG Power operates. The ISOs act similarly to a clearing house for all of its members in that all revenues paid out are collected from market participants based on their consumption of energy and energy-related products. PSEG Power also enters into bilateral contracts for energy, capacity, FTRs, gas, emission allowances and other energy-related contracts to optimize the value of its portfolio of generating assets and its electric and gas supply obligations. In addition, PSEG Power’s Salem 1, Salem 2 and Hope Creek nuclear plants receive ZEC revenue from the EDCs in New Jersey including PSE&G.
Other
This category includes amounts applicable to Energy Holdings and PSEG LI, which are below the quantitative threshold for separate disclosure as reportable segments. Other also includes amounts applicable to PSEG (parent corporation) and Services.
             
   PSE&G Power Other (A) Eliminations (B) 
Consolidated
Total
 
   Millions 
 Year Ended December 31, 2017           
 Operating Revenues $6,234
 $3,930
 $466
 $(1,546) $9,084
 
 Depreciation and Amortization 685
 1,268
 33
 —
 1,986
 
 Operating Income (Loss) 1,752
 (359) 36
 —
 1,429
 
 Income from Equity Method Investments —
 14
 —
 —
 14
 
 Interest Income 24
 3
 5
 (2) 30
 
 Interest Expense 303
 50
 40
 (2) 391
 
 Income (Loss) before Income Taxes 1,536
 (250) (18) —
 1,268
 
 Income Tax Expense (Benefit) 563
 (729) (140) —
 (306) 
 Net Income (Loss) 973
 479
 122
 —
 1,574
 
 Gross Additions to Long-Lived Assets $2,919
 $1,231
 $40
 $—
 $4,190
 
 As of December 31, 2017           
 Total Assets $28,554
 $12,418
 $2,666
 $(922) $42,716
 
 Investments in Equity Method Subsidiaries $—
 $87
 $—
 $—
 $87
 
             

PSE&GPSEG PowerOther (A)Eliminations (B)Consolidated
Total
 Millions
Year Ended December 31, 2020
Operating Revenues$6,608 $3,634 $595 $(1,234)$9,603 
Depreciation and Amortization887 368 30 0 1,285 
Operating Income (Loss)1,639 603 28 0 2,270 
Income from Equity Method Investments0 14 0 0 14 
Interest Income17 6 5 (3)25 
Interest Expense388 121 94 (3)600 
Income (Loss) before Income Taxes1,567 782 (48)0 2,301 
Income Tax Expense (Benefit)240 188 (32)0 396 
Net Income (Loss) (C)$1,327 $594 $(16)$0 $1,905 
Gross Additions to Long-Lived Assets$2,507 $404 $12 $0 $2,923 
As of December 31, 2020
Total Assets$35,581 $12,704 $2,692 $(927)$50,050 
Investments in Equity Method Subsidiaries$0 $64 $0 $0 $64 
172
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PSE&GPSEG PowerOther (A)Eliminations (B)Consolidated
Total
 Millions
Year Ended December 31, 2019
Operating Revenues$6,625 $4,385 $549 $(1,483)$10,076 
Depreciation and Amortization837 377 34 0 1,248 
Operating Income (Loss)1,469 448 26 0 1,943 
Income from Equity Method Investments0 14 0 0 14 
Interest Income18 7 6 (5)26 
Interest Expense361 119 94 (5)569 
Income (Loss) before Income Taxes1,343 671 (64)0 1,950 
Income Tax Expense (Benefit)93 203 (39)0 257 
Net Income (Loss) (C)$1,250 $468 $(25)$0 $1,693 
Gross Additions to Long-Lived Assets$2,542 $607 $17 $0 $3,166 
As of December 31, 2019
Total Assets$33,266 $12,805 $2,715 $(1,056)$47,730 
Investments in Equity Method Subsidiaries$0 $66 $1 $0 $67 
PSE&GPSEG PowerOther (A)Eliminations (B)Consolidated
Total
 Millions
Year Ended December 31, 2018
Operating Revenues$6,471 $4,146 $571 $(1,492)$9,696 
Depreciation and Amortization770 354 34 0 1,158 
Operating Income (Loss)1,606 596 96 0 2,298 
Income from Equity Method Investments0 15 0 0 15 
Interest Income21 5 9 (6)29 
Interest Expense333 76 73 (6)476 
Income (Loss) before Income Taxes1,411 431 13 0 1,855 
Income Tax Expense (Benefit)344 66 7 0 417 
Net Income (Loss)$1,067 $365 $6 $0 $1,438 
Gross Additions to Long-Lived Assets$2,896 $996 $20 $0 $3,912 
As of December 31, 2018
Total Assets$31,109 $12,594 $2,604 $(981)$45,326 
Investments in Equity Method Subsidiaries$0 $86 $0 $0 $86 
(A)Includes amounts applicable to Energy Holdings and PSEG LI, which are below the quantitative threshold for separate disclosure as reportable segments. Other also includes amounts applicable to PSEG (parent corporation) and Services.
(B)Intercompany eliminations primarily relate to intercompany transactions between PSE&G and PSEG Power. For a further discussion of the intercompany transactions between PSE&G and PSEG Power, see Note 26. Related-Party Transactions.
(C)Includes an after-tax gain of $86 million in the year ended December 31, 2020 related to the sale of PSEG Power’s interest in the Yards Creek generation facility and an after-tax loss of $286 million in the year ended December 31, 2019 related to the sale of PSEG Power’s ownership interests in the Keystone and Conemaugh fossil generation plants. See Note 4. Early Plant Retirements/Asset Dispositions for additional information.
179
             
   PSE&G Power Other (A) Eliminations (B) 
Consolidated
Total
 
   Millions 
 Year Ended December 31, 2016           
 Operating Revenues $6,221
 $4,023
 $370
 $(1,553) $9,061
 
 Depreciation and Amortization 565
 881
 30
 —
 1,476
 
 Operating Income (Loss) 1,614
 13
 (51) —
 1,576
 
 Income from Equity Method Investments —
 11
 —
 —
 11
 
 Interest Income 24
 4
 4
 (2) 30
 
 Interest Expense 289
 84
 14
 (2) 385
 
 Income (Loss) before Income Taxes 1,404
 (43) (63) —
 1,298
 
 Income Tax Expense (Benefit) 515
 (61) (43) —
 411
 
 Net Income (Loss) 889
 18
 (20) —
 887
 
 Gross Additions to Long-Lived Assets $2,816
 $1,343
 $40
 $—
 $4,199
 
 As of December 31, 2016           
 Total Assets $26,288
 $12,193
 $2,373
 $(784) $40,070
 
 Investments in Equity Method Subsidiaries $—
 $102
 $—
 $—
 $102
 
             
             
   PSE&G Power Other (A) Eliminations (B) 
Consolidated
Total
 
   Millions 
 Year Ended December 31, 2015           
 Operating Revenues $6,636
 $4,928
 $462
 $(1,611) $10,415
 
 Depreciation and Amortization 892
 291
 31
 —
 1,214
 
 Operating Income (Loss) 1,462
 1,430
 70
 —
 2,962
 
 Income from Equity Method Investments —
 14
 (2) —
 12
 
 Interest Income 25
 2
 33
 (29) 31
 
 Interest Expense 280
 121
 21
 (29) 393
 
 Income (Loss) before Income Taxes 1,257
 1,367
 56
 —
 2,680
 
 Income Tax Expense (Benefit) 470
 511
 20
 —
 1,001
 
 Net Income (Loss) 787
 856
 36
 —
 1,679
 
 Gross Additions to Long-Lived Assets $2,692
 $1,117
 $54
 $—
 $3,863
 
 As of December 31, 2015           
 Total Assets $23,677
 $12,250
 $2,810
 $(1,202) $37,535
 
 Investments in Equity Method Subsidiaries $—
 $119
 $—
 $—
 $119
 
             
(A)Includes amounts applicable to Energy Holdings and PSEG LI, which are below the quantitative threshold for separate disclosure as reportable segments. Other also includes amounts applicable to PSEG (parent corporation) and Services.
(B)Intercompany eliminations primarily relate to intercompany transactions between PSE&G and Power. For a further discussion of the intercompany transactions between PSE&G and Power, see Note 24. Related-Party Transactions.


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Note 24.26. Related-Party Transactions
The following discussion relates to intercompany transactions, which are eliminated during the PSEG consolidation process in accordance with GAAP.
PSE&G
The financial statements for PSE&G include transactions with related parties presented as follows:
 Years Ended December 31,
Related Party Transactions202020192018
 Millions
Billings from Affiliates:
Net Billings from PSEG Power (A)$1,207 $1,512 $1,514 
Administrative Billings from Services (B)337 310 333 
Total Billings from Affiliates$1,544 $1,822 $1,847 
         
   Years Ended December 31, 
 Related Party Transactions 2017 2016 2015 
   Millions 
 Billings from Affiliates:       
 Net Billings from Power primarily through BGS and BGSS (A) $1,580
 $1,587
 $1,630
 
 Administrative Billings from Services (B) 331
 312
 274
 
 Total Billings from Affiliates $1,911
 $1,899
 $1,904
 
         
 Years Ended December 31,
Related Party Transactions20202019
 Millions
Receivables from PSEG (C)$0 $1 
Payable to PSEG Power (A)$273 $307 
Payable to Services (B)95 83 
Payable to PSEG (C)111 0 
Accounts Payable—Affiliated Companies$479 $390 
Working Capital Advances to Services (D)$33 $33 
Long-Term Accrued Taxes Payable$7 $115 
       
   Years Ended December 31, 
 Related Party Transactions 2017 2016 
   Millions 
 Receivables from PSEG (C) $—
 $76
 
 Payable to Power (A) $221
 $193
 
 Payable to Services (B) 78
 67
 
 Payable to PSEG (C) $41
 $—
 
 Accounts Payable—Affiliated Companies $340
 $260
 
 Working Capital Advances to Services (D) $33
 $33
 
 Long-Term Accrued Taxes Payable $91
 $130
 
       
PSEG Power
The financial statements for PSEG Power include transactions with related parties presented as follows:
         
   Years Ended December 31, 
 Related Party Transactions 2017 2016 2015 
   Millions 
 Billings to Affiliates:       
 Net Billings to PSE&G primarily through BGS and BGSS (A) $1,580
 $1,587
 $1,630
 
 Billings from Affiliates:       
 Administrative Billings from Services (B) $168
 $179
 $187
 
         

 Years Ended December 31,
Related Party Transactions202020192018
 Millions
Billings to Affiliates:
Net Billings to PSE&G (A)$1,207 $1,512 1,514 
Billings from Affiliates:
Administrative Billings from Services (B)$160 $156 $145 
174
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


 Years Ended December 31,
Related Party Transactions20202019
 Millions
Receivable from PSE&G (A)$273 $307 
Receivables from PSEG (C)44 101 
Accounts Receivable—Affiliated Companies$317 $408 
Payable to Services (B)$13 $5 
Accounts Payable—Affiliated Companies$13 $5 
Short-Term Loan to (from) Affiliate (E)$161 $149 
Working Capital Advances to Services (D)$17 $17 
Long-Term Accrued Taxes Payable$57 $115 
(A)PSE&G has entered into a requirements contract with PSEG Power under which PSEG Power provides the gas supply services needed to meet PSE&G’s BGSS and other contractual requirements. PSEG Power has also entered into contracts to supply energy, capacity and ancillary services to PSE&G through the BGS auction process and sells ZECs to PSE&G under the ZEC program. The rates in the BGS and BGSS contracts and for the ZEC sales are prescribed by the BPU. BGS and BGSS sales are billed and settled on a monthly basis. ZEC sales are billed on a monthly basis and settled annually following completion of each energy year. In addition, PSEG Power and PSE&G provide certain technical services for each other generally at cost in compliance with FERC and BPU affiliate rules.
(B)Services provides and bills administrative services to PSE&G and PSEG Power at cost. In addition, PSE&G and PSEG Power have other payables to Services, including amounts related to certain common costs, which Services pays on behalf of each of the operating companies.
(C)PSEG files a consolidated federal income tax return with its affiliated companies. A tax allocation agreement exists between PSEG and each of its affiliated companies. The general operation of these agreements is that the subsidiary company will compute its taxable income on a stand-alone basis. If the result is a net tax liability, such amount shall be paid to PSEG. If there are NOLs and/or tax credits, the subsidiary shall receive payment for the tax savings from PSEG to the extent that PSEG is able to utilize those benefits.
(D)PSE&G and PSEG Power have advanced working capital to Services. The amounts are included in Other Noncurrent Assets on PSE&G’s and PSEG Power’s Consolidated Balance Sheets.
(E)PSEG Power’s short-term loans with PSEG are for working capital and other short-term needs. Interest Income and Interest Expense relating to these short-term funding activities were immaterial.


181
       
   Years Ended December 31, 
 Related Party Transactions 2017 2016 
   Millions 
 Receivable from PSE&G (A) $221
 $193
 
 Receivable from PSEG (C) —
 12
 
 Accounts Receivable—Affiliated Companies $221
 $205
 
 Payable to Services (B) $28
 $25
 
 Payable to PSEG (C) 29
 —
 
 Accounts Payable—Affiliated Companies $57
 $25
 
 Short-Term Loan due (to) from Affiliate (E) $(281) $87
 
 Working Capital Advances to Services (D) $17
 $17
 
 Long-Term Accrued Taxes Payable $52
 $77
 
       
(A)PSE&G has entered into a requirements contract with Power under which Power provides the gas supply services needed to meet PSE&G’s BGSS and other contractual requirements. Power has also entered into contracts to supply energy, capacity and ancillary services to PSE&G through the BGS auction process. The rates in the BGS and BGSS contracts are prescribed by the BPU. In addition, Power and PSE&G provide certain technical services for each other generally at cost in compliance with FERC and BPU affiliate rules.
(B)Services provides and bills administrative services to PSE&G and Power at cost. In addition, PSE&G and Power have other payables to Services, including amounts related to certain common costs, such as pension and OPEB costs, which Services pays on behalf of each of the operating companies.
(C)PSEG files a consolidated federal income tax return with its affiliated companies. A tax allocation agreement exists between PSEG and each of its affiliated companies. The general operation of these agreements is that the subsidiary company will compute its taxable income on a stand-alone basis. If the result is a net tax liability, such amount shall be paid to PSEG. If there are net operating losses and/or tax credits, the subsidiary shall receive payment for the tax savings from PSEG to the extent that PSEG is able to utilize those benefits.
(D)PSE&G and Power have advanced working capital to Services. The amounts are included in Other Noncurrent Assets on PSE&G’s and Power’s Consolidated Balance Sheets.
(E)Power’s short-term loans with PSEG are for working capital and other short-term needs. Interest Income and Interest Expense relating to these short-term funding activities were immaterial.

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Note 25. Selected Quarterly Data (Unaudited)
The information shown in the following tables, in the opinion of PSEG, PSE&G and Power includes all adjustments, consisting only of normal recurring accruals, necessary to fairly present such amounts.
                   
   Quarter Ended 
   March 31, June 30, September 30, December 31, (A) 
   2017 2016 2017 2016 2017 2016 2017 2016 
 PSEG Consolidated: Millions, except per share data 
 Operating Revenues $2,592
 $2,616
 $2,133
 $1,905
 $2,263
 $2,450
 $2,096
 $2,090
 
 Operating Income (Loss) $178
 $827
 $196
 $347
 $693
 $577
 $362
 $(175) 
 Net Income (Loss) $114
 $471
 $109
 $187
 $395
 $327
 $956
 $(98) 
 Earnings Per Share:                 
 Basic:                 
 Net Income (Loss) $0.23
 $0.93
 $0.22
 $0.37
 $0.78
 $0.65
 $1.89
 $(0.19) 
 Diluted:                 
 Net Income (Loss) $0.22
 $0.93
 $0.22
 $0.37
 $0.78
 $0.64
 $1.88
 $(0.19) 
 Weighted Average Common Shares Outstanding:                 
 Basic 505
 505
 505
 505
 505
 505
 505
 505
 
 Diluted 508
 508
 507
 508
 507
 508
 508
 508
 
                   
                   
   Quarter Ended 
   March 31, June 30, September 30, December 31, 
   2017 2016 2017 2016 2017 2016 2017 2016 
 PSE&G: Millions 
 Operating Revenues $1,812
 $1,712
 $1,368
 $1,350
 $1,509
 $1,684
 $1,545
 $1,475
 
 Operating Income $521
 $462
 $379
 $333
 $459
 $450
 $393
 $369
 
 Net Income $299
 $262
 $208
 $179
 $246
 $255
 $220
 $193
 
                   
                   
   Quarter Ended 
   March 31, June 30, September 30, December 31, (A) 
   2017 2016 2017 2016 2017 2016 2017 2016 
 Power: Millions 
 Operating Revenues $1,284
 $1,313
 $929
 $714
 $873
 $1,075
 $844
 $921
 
 Operating Income (Loss) $(303) $343
 $(187) $(12) $213
 $238
 $(82) $(556) 
 Net Income (Loss) $(170) $192
 $(97) $(11) $136
 $139
 $610
 $(302) 
                   
(A)The increases in Operating Income at PSEG consolidated and Power in the fourth quarter 2017 as compared to the same quarter in 2016 were primarily due to higher costs in 2016 related to closing the coal/gas Hudson and Mercer units, which were fully depreciated as of June 1, 2017. The increases in Net Income at PSEG consolidated and Power in the fourth quarter 2017 as compared to the same quarter in 2016 also includes the impact of the remeasurement of deferred tax balances resulting from the enactment of new tax legislation in December 2017. See Note 20. Income Taxes for additional information.



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Note 26. Guarantees of Debt
Power’s Senior Notes are fully and unconditionally and jointly and severally guaranteed by its subsidiaries, PSEG Fossil LLC, PSEG Nuclear LLC and PSEG Energy Resources & Trade LLC. The following tables present condensed financial information for the guarantor subsidiaries, as well as Power’s non-guarantor subsidiaries, as of December 31, 2017 and 2016 and for the years ended December 31, 2017, 2016 and 2015.
             
   Power 
Guarantor
Subsidiaries
 
Other
Subsidiaries
 
Consolidating
Adjustments
 Total 
   Millions 
 Year Ended December 31, 2017           
 Operating Revenues $—
 $3,891
 $174
 $(135) $3,930
 
 Operating Expenses 8
 4,221
 195
 (135) 4,289
 
 Operating Income (Loss) (8) (330) (21) —
 (359) 
 Equity Earnings (Losses) of Subsidiaries 567
 60
 14
 (627) 14
 
 Other Income 98
 257
 2
 (144) 213
 
 Other Deductions (24) (32) —
 —
 (56) 
 Other-Than-Temporary Impairments —
 (12) —
 —
 (12) 
 Interest Expense (128) (49) (17) 144
 (50) 
 Income Tax Benefit (Expense) (26) 588
 167
 —
 729
 
 Net Income (Loss) $479
 $482
 $145
 $(627) $479
 
   Comprehensive Income (Loss) $518
 $529
 $145
 $(674) $518
 
 As of December 31, 2017           
 Current Assets $4,327
 $1,500
 $200
 $(4,686) $1,341
 
 Property, Plant and Equipment, net 54
 5,778
 2,764
 —
 8,596
 
 Investment in Subsidiaries 4,844
 404
 —
 (5,248) —
 
 Noncurrent Assets 100
 2,349
 110
 (78) 2,481
 
 Total Assets $9,325
 $10,031
 $3,074
 $(10,012) $12,418
 
 Current Liabilities $689
 $3,586
 $1,846
 $(4,686) $1,435
 
 Noncurrent Liabilities 533
 1,966
 459
 (78) 2,880
 
 Long-Term Debt 2,136
 —
 —
 —
 2,136
 
 Member’s Equity 5,967
 4,479
 769
 (5,248) 5,967
 
 Total Liabilities and Member’s Equity $9,325
 $10,031
 $3,074
 $(10,012) $12,418
 
 Year Ended December 31, 2017           
 Net Cash Provided By (Used In) Operating Activities $(42) $1,185
 $238
 $(55) $1,326
 
 Net Cash Provided By (Used In) Investing Activities $506
 $(448) $(525) $(765) $(1,232) 
 Net Cash Provided By (Used In) Financing Activities $(464) $(736) $307
 $820
 $(73) 
             



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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

             
   Power 
Guarantor
Subsidiaries
 
Other
Subsidiaries
 
Consolidating
Adjustments
 Total 
   Millions 
 Year Ended December 31, 2016           
 Operating Revenues $—
 $3,971
 $173
 $(121) $4,023
 
 Operating Expenses 8
 3,962
 161
 (121) 4,010
 
 Operating Income (Loss) (8) 9
 12
 —
 13
 
 Equity Earnings (Losses) of Subsidiaries 36
 (3) 11
 (33) 11
 
 Other Income 71
 120
 —
 (89) 102
 
 Other Deductions (18) (39) —
 —
 (57) 
 Other-Than-Temporary Impairments —
 (28) —
 —
 (28) 
 Interest Expense (115) (40) (18) 89
 (84) 
 Income Tax Benefit (Expense) 52
 (11) 20
 —
 61
 
 Net Income (Loss) $18
 $8
 $25
 $(33) $18
 
   Comprehensive Income (Loss) $47
 $50
 $25
 $(75) $47
 
 As of December 31, 2016           
 Current Assets $4,412
 $1,593
 $152
 $(4,697) $1,460
 
 Property, Plant and Equipment, net 55
 6,145
 2,320
 —
 8,520
 
 Investment in Subsidiaries 4,249
 344
 —
 (4,593) —
 
 Noncurrent Assets 168
 2,016
 129
 (100) 2,213
 
 Total Assets $8,884
 $10,098
 $2,601
 $(9,390) $12,193
 
 Current Liabilities $171
 $3,752
 $1,454
 $(4,697) $680
 
 Noncurrent Liabilities 532
 2,398
 502
 (100) 3,332
 
 Long-Term Debt 2,382
 —
 —
 —
 2,382
 
 Member’s Equity 5,799
 3,948
 645
 (4,593) 5,799
 
 Total Liabilities and Member’s Equity $8,884
 $10,098
 $2,601
 $(9,390) $12,193
 
 Year Ended December 31, 2016           
 Net Cash Provided By (Used In) Operating Activities $97
 $1,442
 $323
 $(607) $1,255
 
 Net Cash Provided By (Used In) Investing Activities $60
 $(707) $(789) $289
 $(1,147) 
 Net Cash Provided By (Used In) Financing Activities $(157) $(736) $466
 $318
 $(109) 
             

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   Power 
Guarantor
Subsidiaries
 
Other
Subsidiaries
 
Consolidating
Adjustments
 Total 
   Millions 
 Year Ended December 31, 2015           
 Operating Revenues $—
 $4,883
 $179
 $(134) $4,928
 
 Operating Expenses 12
 3,451
 169
 (134) 3,498
 
 Operating Income (Loss) (12) 1,432
 10
 —
 1,430
 
 Equity Earnings (Losses) of Subsidiaries 906
 (4) 14
 (902) 14
 
 Other Income 48
 174
 —
 (53) 169
 
 Other Deductions (27) (45) —
 —
 (72) 
 Other-Than-Temporary Impairments —
 (53) —
 —
 (53) 
 Interest Expense (116) (39) (19) 53
 (121) 
 Income Tax Benefit (Expense) 57
 (574) 6
 —
 (511) 
 Net Income (Loss) $856
 $891
 $11
 $(902) $856
 
   Comprehensive Income (Loss) $844
 $855
 $11
 $(866) $844
 
 Year Ended December 31, 2015           
 Net Cash Provided By (Used In) Operating Activities $571
 $2,089
 $80
 $(1,034) $1,706
 
 Net Cash Provided By (Used In) Investing Activities $(366) $(1,519) $(430) $1,314
 $(1,001) 
 Net Cash Provided By (Used In) Financing Activities $(205) $(571) $354
 $(280) $(702) 
             




















179


ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE
None.




ITEM 9A. CONTROLS AND PROCEDURES
Disclosure Controls and Procedures
PSEG, PSE&G and PSEG Power
We have established and maintain disclosure controls and procedures as defined under Rule 13a-15(e) and 15d-15(e) promulgated under the Securities Exchange Act of 1934, as amended (the “Exchange Act”) that are designed to provide reasonable assurance that information required to be disclosed in the reports that are filed or submitted under the Exchange Act is recorded, processed, summarized and reported and is accumulated and communicated to the Chief Executive Officer (CEO) and Chief Financial Officer (CFO) of each respective company, as appropriate, by others within the entities to allow timely decisions regarding required disclosure. We have established a disclosure committee which includes several key management employees and which reports directly to the CFO and CEO of each of PSEG, PSE&G and PSEG Power. The committee monitors and evaluates the effectiveness of these disclosure controls and procedures. The CFO and CEO of each of PSEG, PSE&G and PSEG Power have evaluated the effectiveness of the disclosure controls and procedures and, based on this evaluation, have concluded that disclosure controls and procedures at each respective company were effective at a reasonable assurance level as of the end of the period covered by the report.
Internal Controls
PSEG, PSE&G and PSEG Power
We have conducted assessments of our internal control over financial reporting as of December 31, 2017,2020, as required by Section 404 of the Sarbanes-Oxley Act, using the framework promulgated by the Committee of Sponsoring Organizations of the Treadway Commission, commonly referred to as “COSO.” Managements’ reports on PSEG’s, PSE&G’s and PSEG Power’s internal control over financial reporting are included on pages 181, 182183, 184 and 183,185, respectively. The Independent Registered Public Accounting Firm’s report with respect to the effectiveness of PSEG’s internal control over financial reporting is included on page 184.186. Management has concluded that internal control over financial reporting is effective as of December 31, 2017.2020.
We continually review our disclosure controls and procedures and make changes, as necessary, to ensure the quality of our financial reporting. There have been no changes in internal control over financial reporting that occurred during the fourth quarter of 20172020 that have materially affected, or are reasonably likely to materially affect, each registrant’s internal control over financial reporting.


ITEM 9B. OTHER INFORMATION
None.





180
182





MANAGEMENT REPORT ON INTERNAL CONTROL OVER
FINANCIAL REPORTING—PSEG
Management of Public Service Enterprise Group Incorporated (PSEG) is responsible for establishing and maintaining effective internal control over financial reporting and for the assessment of the effectiveness of internal control over financial reporting. As defined by the SEC in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and implemented by the company’s management and other personnel, with oversight by the Audit Committee of the Board of Directors to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America (generally accepted accounting principles).
PSEG’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of PSEG’s assets; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of PSEG are being made only in accordance with authorizations of PSEG’s management and directors; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of PSEG’s assets that could have a material effect on the financial statements.
In connection with the preparation of PSEG’s annual financial statements, management of PSEG has undertaken an assessment, which includes the design and operational effectiveness of PSEG’s internal control over financial reporting based on criteria established in the Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, commonly referred to as “COSO”. The COSO framework is based upon five integrated components of control: control environment, risk assessment, control activities, information and communications and ongoing monitoring.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projection of any evaluation of effectiveness to future periods is subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Based on the assessment performed, management has concluded that PSEG’s internal control over financial reporting is effective and provides reasonable assurance regarding the reliability of PSEG’s financial reporting and the preparation of its financial statements as of December 31, 20172020 in accordance with generally accepted accounting principles. Further, management has not identified any material weaknesses in internal control over financial reporting as of December 31, 2017.2020.
PSEG’s external auditors, Deloitte & Touche LLP, have audited PSEG’s financial statements for the year ended December 31, 20172020 included in this annual report on Form 10-K and, as part of that audit, have issued a report on the effectiveness of PSEG’s internal control over financial reporting, a copy of which is included in this annual report on Form 10-K.
 
/s/ RALPH IZZO
Chief Executive Officer
/s/ RALPH IZZODANIEL J. CREGG
Chief Executive Officer
/s/ DANIEL J. CREGG
Chief Financial Officer
February 26, 20182021





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MANAGEMENT REPORT ON INTERNAL CONTROL OVER
FINANCIAL REPORTING—PSE&G
Management of Public Service Electric and Gas Company (PSE&G) is responsible for establishing and maintaining effective internal control over financial reporting and for the assessment of the effectiveness of internal control over financial reporting. As defined by the SEC in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and implemented by the company’s management and other personnel, with oversight by the Audit Committee of the Board of Directors of its parent, Public Service Enterprise Group Incorporated, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America (generally accepted accounting principles).
PSE&G’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of PSE&G’s assets; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of PSE&G are being made only in accordance with authorizations of PSE&G’s management and directors; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of PSE&G’s assets that could have a material effect on the financial statements.
In connection with the preparation of PSE&G’s annual financial statements, management of PSE&G has undertaken an assessment, which includes the design and operational effectiveness of PSE&G’s internal control over financial reporting based on criteria established in the Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, commonly referred to as “COSO”. The COSO framework is based upon five integrated components of control: control environment, risk assessment, control activities, information and communications and ongoing monitoring.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projection of any evaluation of effectiveness to future periods is subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Based on the assessment performed, management has concluded that PSE&G’s internal control over financial reporting is effective and provides reasonable assurance regarding the reliability of PSE&G’s financial reporting and the preparation of its financial statements as of December 31, 20172020 in accordance with generally accepted accounting principles. Further, management has not identified any material weaknesses in internal control over financial reporting as of December 31, 2017.
2020.
/s/ RALPH IZZO
Chief Executive Officer
/s/ RALPH IZZODANIEL J. CREGG
Chief Executive Officer
/s/ DANIEL J. CREGG
Chief Financial Officer
February 26, 20182021







182
184





MANAGEMENT REPORT ON INTERNAL CONTROL OVER
FINANCIAL REPORTING—PSEG Power
Management of PSEG Power LLC (Power)(PSEG Power) is responsible for establishing and maintaining effective internal control over financial reporting and for the assessment of the effectiveness of internal control over financial reporting. As defined by the SEC in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and implemented by the company’s management and other personnel, with oversight by the Audit Committee of the Board of Directors of its parent, Public Service Enterprise Group Incorporated, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America (generally accepted accounting principles).
PSEG Power’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of PSEG Power’s assets; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of PSEG Power are being made only in accordance with authorizations of PSEG Power’s management and directors; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of PSEG Power’s assets that could have a material effect on the financial statements.
In connection with the preparation of PSEG Power’s annual financial statements, management of PSEG Power has undertaken an assessment, which includes the design and operational effectiveness of PSEG Power’s internal control over financial reporting based on criteria established in the Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, commonly referred to as “COSO”. The COSO framework is based upon five integrated components of control: control environment, risk assessment, control activities, information and communications and ongoing monitoring.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projection of any evaluation of effectiveness to future periods is subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Based on the assessment performed, management has concluded that PSEG Power’s internal control over financial reporting is effective and provides reasonable assurance regarding the reliability of PSEG Power’s financial reporting and the preparation of its financial statements as of December 31, 20172020 in accordance with generally accepted accounting principles. Further, management has not identified any material weaknesses in internal control over financial reporting as of December 31, 2017.
2020.
/s/ RALPH IZZO
Chief Executive Officer
/s/ RALPH IZZODANIEL J. CREGG
Chief Executive Officer
/s/ DANIEL J. CREGG
Chief Financial Officer
February 26, 20182021







183
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of
Public Service Enterprise Group Incorporated
Newark, New Jersey
Opinion on Internal Control over Financial Reporting
We have audited the internal control over financial reporting of Public Service Enterprise Group Incorporated and subsidiaries (the “Company”) as of December 31, 2017,2020, based on criteria established in Internal Control - — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”)(COSO). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017,2020, based on criteria established in Internal Control -— Integrated Framework (2013) issued by COSO.
We have also audited,in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”)(PCAOB), the consolidated financial statements and the consolidated financial statement schedule listed in the Index at Item 15(B)(a) as of and for the year ended December 31, 20172020 of the Company and our report dated February 26, 2018,2021 expressed an unqualified opinion on those financial statements.
Basis for Opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management Report on Internal Control Over Financial Reporting - PSEG. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB.Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.












/s/ DELOITTE & TOUCHE LLP
Parsippany, New Jersey
February 26, 2018

2021
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PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE
GOVERNANCE
Executive Officers
PSEG
The information required by Item 10 of Form 10-K with respect to executive officers is set forth in Part I. Information About Our Executive Officers of the Registrant (PSEG).
PSE&G and PSEG Power
Omitted pursuant to conditions set forth in General Instruction I of Form 10-K.
Directors
PSEG
The information required by Item 10 of Form 10-K with respect to (i) present directors of PSEG who are nominees for election as directors at PSEG’s 20182021 Annual Meeting of Stockholders, (ii) the director nomination process, and (iii) the composition of the Audit Committee of the Board, is set forth under the headings “Nominees For Director-Biographical Information,” “Overview of Board Nominees-Board Refreshment and Election-Board CompositionTenure,” and Individual Qualifications,” “Nominees and Election-Nomination Process,“-Board Membership Selection,” and “Corporate Governance-Board Committee Responsibilities-Audit Committee,Committees,” respectively, in PSEG’s definitive Proxy Statement for such Annual Meeting of Stockholders, which definitive Proxy Statement is expected to be filed with the U.S. Securities and Exchange Commission (SEC) on or about March 12, 201815, 2021 and which information set forth under said heading is incorporated herein by this reference thereto.
PSE&G and PSEG Power
Omitted pursuant to conditions set forth in General Instruction I of Form 10-K.
Standards of Conduct
Our Standards of Conduct (Standards) is a code of ethics applicable to us and our subsidiaries. The Standards are an integral part of our business conduct compliance program and embody our commitment to conduct operations in accordance with the highest legal and ethical standards. The Standards apply to all of our directors and employees (including PSE&G’s, PSEG Power’s, Energy Holdings’ and Services’ respective principal executive officer, principal financial officer, principal accounting officer or Controller and persons performing similar functions). Each such person is responsible for understanding and complying with the Standards. The Standards are posted on our website, www.pseg.com/info/investors/governance/document.jsphttps://corporate.pseg.com/aboutpseg/leadershipandgovernance/standardsofconduct. We will send youYou can get a free copy on request.of the Standards by making an oral or written request directed to:
Vice President, Investor Relations
PSEG Services Corporation
80 Park Plaza, 4th Floor
Newark, NJ 07102
Telephone (973) 430-6565
The Standards establish a set of common expectations for behavior to which each employee must adhere in dealings with investors, customers, fellow employees, competitors, vendors, government officials, the media and all others who may associate their words and actions with us. The Standards have been developed to provide reasonable assurance that, in conducting our business, employees behave ethically and in accordance with the law and do not take advantage of investors, regulators or customers through manipulation, abuse of confidential information or misrepresentation of material facts.
We will post on our website, www.pseg.com/info/investors/governance/document.jsp:https://corporate.pseg.com/aboutpseg/leadershipandgovernance/standardsofconduct:
•Any amendment (other than one that is technical, administrative or non-substantive) that we adopt to our Standards; and
•Any grant by us of a waiver from the Standards that applies to any director or executive officer and that relates to any element enumerated by the SEC.
In 2017,2020, we did not grant any waivers to the Standards.
187



Section 16(a) Beneficial Ownership Reporting Compliance
PSEG
The information required by Item 10 of Form 10-K with respect to compliance with Section 16(a) of the Securities Exchange Act of 1934, as amended, is set forth under the heading “Section“Security Ownership of Directors, Management and Certain Beneficial Owners-Delinquent Section 16(a) Beneficial Ownership Reporting Compliance,”Reports” in

185

PSEG’s definitive Proxy Statement for the 20182021 Annual Meeting of Stockholders, which definitive Proxy Statement is expected to be filed with the SEC on or about March 12, 201815, 2021 and which information set forth under said heading is incorporated herein by this reference thereto.
PowerPSE&G and PSE&GPSEG Power
Omitted pursuant to conditions set forth in General Instruction I of Form 10-K.


ITEM 11. EXECUTIVE COMPENSATION
PSEG
The information required by Item 11 of Form 10-K is set forth in PSEG’s definitive Proxy Statement for the 20182021 Annual Meeting of Stockholders which definitive Proxy Statement is expected to be filed with the SEC on or about March 12, 201815, 2021 and such information set forth under such heading is incorporated herein by this reference thereto.
PowerPSE&G and PSE&GPSEG Power
Omitted pursuant to conditions set forth in General Instruction I of Form 10-K.


ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
AND MANAGEMENT AND RELATED STOCKHOLDERSSTOCKHOLDER MATTERS
PSEG
The information required by Item 12 of Form 10-K with respect to directors, executive officers and certain beneficial owners is set forth under the heading “Security Ownership of Directors, Management and Certain Beneficial Owners” in PSEG’s definitive Proxy Statement for the 20182021 Annual Meeting of Stockholders which definitive Proxy Statement is expected to be filed with the SEC on or about March 12, 201815, 2021 and such information set forth under such heading is incorporated herein by this reference thereto.
For information relating to securities authorized for issuance under equity compensation plans, see Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.
PowerPSE&G and PSE&GPSEG Power
Omitted pursuant to conditions set forth in General Instruction I of Form 10-K.


ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND
DIRECTOR INDEPENDENCE
PSEG
The information required by Item 13 of Form 10-K is set forth under the heading “Corporate Governance—Transactions withGovernance-Certain Relationships and Related Persons”Person Transactions” in PSEG’s definitive Proxy Statement for the 20182021 Annual Meeting of Stockholders which definitive Proxy Statement is expected to be filed with the SEC on or about March 12, 201815, 2021 and such information set forth under such heading is incorporated herein by this reference thereto.
PowerPSE&G and PSE&GPSEG Power
Omitted pursuant to conditions set forth in General Instruction I of Form 10K.10-K.


ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
The information required by Item 14 of Form 10-K is set forth under the heading “Fees Billed by Deloitte & Touche LLP for 20172020 and 2016”2019” in PSEG’s definitive Proxy Statement for the 20182021 Annual Meeting of Stockholders which definitive Proxy Statement is expected to be filed with the SEC on or about March 12, 2018.15, 2021. Such information set forth under such heading is incorporated herein by this reference hereto.

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PART IV




ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES


(A) The following Financial Statements are filed as a part of this report:


a.Public Service Enterprise Group Incorporated’s Consolidated Balance Sheets as of December 31, 2017 and 2016 and the related Consolidated Statements of Operations, Comprehensive Income, Cash Flows and Stockholders’ Equity for the three years ended December 31, 2017 on pages 77 through 82.

a.Public Service Enterprise Group Incorporated’s Consolidated Balance Sheets as of December 31, 2020 and 2019 and the related Consolidated Statements of Operations, Comprehensive Income, Cash Flows and Stockholders’ Equity for the three years ended December 31, 2020 on pages 74 through 79.
b.Public Service Electric and Gas Company’s Consolidated Balance Sheets as of December 31, 2017 and 2016 and the related Consolidated Statements of Operations, Comprehensive Income, Cash Flows and Common Stockholder’s Equity for the three years ended December 31, 2017 on pages 83 through 88.


c.PSEG Power LLC’s Consolidated Balance Sheets as of December 31, 2017 and 2016 and the related Consolidated Statements of Operations, Comprehensive Income, Cash Flows and Capitalization and Member’s Equity for the three years ended December 31, 2017 on pages 89 through 94.

b.Public Service Electric and Gas Company’s Consolidated Balance Sheets as of December 31, 2020 and 2019 and the related Consolidated Statements of Operations, Comprehensive Income, Cash Flows and Common Stockholder’s Equity for the three years ended December 31, 2020 on pages 80 through 85.

c.PSEG Power LLC’s Consolidated Balance Sheets as of December 31, 2020 and 2019 and the related Consolidated Statements of Operations, Comprehensive Income, Cash Flows and Capitalization and Member’s Equity for the three years ended December 31, 2020 on pages 86 through 91.

(B) The following documents are filed as a part of this report:


a.PSEG’s Financial Statement Schedules:
a.PSEG’s Financial Statement Schedules:
Schedule II—Valuation and Qualifying Accounts for each of the three years in the period ended December 31, 20172020 (page 193)195).


b.PSE&G’s Financial Statement Schedules:
b.PSE&G’s Financial Statement Schedules:
Schedule II—Valuation and Qualifying Accounts for each of the three years in the period ended December 31, 20172020 (page 193)195).


c.Power’s Financial Statement Schedules:
c.PSEG Power’s Financial Statement Schedules:
Schedule II—Valuation and Qualifying Accounts for each of the three years in the period ended December 31, 20172020 (page 193)195).


Schedules other than those listed above are omitted for the reason that they are not required or are not applicable, or the required information is shown in the consolidated financial statements or notes thereto.
(C) The following documents are filed as part of this report:
LIST OF EXHIBITS:
a.LIST OF EXHIBITS:
a.PSEG:
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Table of Contents


LIST OF EXHIBITS:

187

LIST OF EXHIBITS:
10a(3)
Employment Agreement with William Levis dated December 8, 2006(9)
10a(8)
2001 Long-Term Incentive Plan(13)
10a(9)
Senior Management Incentive Compensation Plan(14)(12)
 
10a(18)
Agreement with Tamara L. Linde dated June 18, 2014(22)(20)
21
Subsidiaries of the Registrant
101.INSInline XBRL Instance Document - The instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.
101.SCHInline XBRL Taxonomy Extension Schema
101.CALInline XBRL Taxonomy Calculation Linkbase
101.LABInline XBRL Taxonomy Extension Labels Linkbase
101.PREInline XBRL Taxonomy Extension Presentation Linkbase
101.DEFInline XBRL Taxonomy Extension Definition Document
104Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)
b.
PSE&G

188

LIST OF EXHIBITS:
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Table of Contents


4a(1)LIST OF EXHIBITS:
4a(1)
Indenture between PSE&G and Fidelity Union Trust Company (now, Wachovia Bank, National Association), as Trustee, dated August 1, 1924(30), securing First and Refunding Mortgage Bond and Supplemental Indentures between PSE&G and U.S. Bank National Association, successor, as Trustee, supplemental to Exhibit 4a(1), dated as follows:
4a(2)
June 1, 1937(31)
4a(3)
July 1, 1937(32)
4a(4)
March 1, 1942(33)
4a(5)
June 1, 1991 (No. 1)(34)
4a(6)
July 1, 1993(35)(33)
May 1, 2012(38)(37)
4a(11)
May 1, 2013(40)(38)
May 1, 2015(42)(40)
4b
4c
Indenture of Trust between PSE&G and Chase Manhattan Bank (National Association) (The Bank of New York Mellon, successor), as Trustee, providing for Secured Medium-Term Notes dated July 1, 1993(44)(45)
10a(7)
2001 Long-Term Incentive Plan(13)
10a(8)
Senior Management Incentive Compensation Plan(14)(12)

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Table of Contents




LIST OF EXHIBITS:
101.INSLIST OF EXHIBITS:
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c.PSEG Power:
10a(4)
Deferred Compensation Plan for Certain Employees, amended Novemberand restated effective January 1, 20112019(11)
10a(6)
2001 Long-Term Incentive Plan(13)
10a(7)
Senior Management Incentive Compensation Plan(14)(12)
10a(13)
Agreement with Tamara L. Linde dated June 18, 2014(22)(20)
31d
Certification by Ralph Izzo, pursuant to Rules 13a-14 and 15d-14 of the 1934 Act
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(1)Filed as Exhibit 3.1a with Quarterly Report on Form 10-Q for the quarter ended March 31, 2007, File No. 001-09120, on May 4, 2007 and incorporated herein by this reference.
(2)Filed as Exhibit 3.1b with Quarterly Report on Form 10-Q for the quarter ended March 31, 2007, File No. 001-09120, on May 4, 2007 and incorporated herein by this reference.

(1)Filed as Exhibit 3.1a with Quarterly Report on Form 10-Q for the quarter ended March 31, 2007, File No. 001-09120, on May 4, 2007 and incorporated herein by this reference.
(2)Filed as Exhibit 3.1b with Quarterly Report on Form 10-Q for the quarter ended March 31, 2007, File No. 001-09120, on May 4, 2007 and incorporated herein by this reference.
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(3)Filed as Exhibit 3.1c with Quarterly Report on Form 10-Q for the quarter ended March 31, 2007, File No. 001-09120, on May 4, 2007 and incorporated herein by this reference.
(3)Filed as Exhibit 3.1c with Quarterly Report on Form 10-Q for the quarter ended March 31, 2007, File No. 001-09120, on May 4, 2007 and incorporated herein by this reference.
(4)Filed as Exhibit 99.1 with Current Report on Form 8-K, File No. 001-09120, on December 16, 2015 and incorporated herein by this reference.
(5)Filed as Exhibit 4(f) with Quarterly Report on Form 10-Q for the quarter ended March 31, 1998, File No. 001-09120, on May 13, 1998 and incorporated herein by this reference.
(6)Filed as Exhibit 4(f) to the Annual Report on Form 10-K for the year ended December 31, 1998, File No. 001-09120, on February 23, 1999 and incorporated herein by this reference
(7)Filed as Exhibit 10.1 with Quarterly Report on Form 10-Q for the quarter ended June 30, 2017, File No. 001-09120, on July 28, 2017 and incorporated herein by this reference.
(8)Filed as Exhibit 10.2 with Quarterly Report on Form 10-Q for the quarter ended June 30, 2017, File No. 001-09120, on July 28, 2017 and incorporated herein by this reference.
(9)Filed as Exhibit 10a(4) with Annual Report on Form 10-K for the year ended December 31, 2007, File Nos. 001-09120 on February 28, 2008 and 000-49614, and incorporated herein by reference.
(10)Filed as Exhibit 10.5 with Quarterly Report on Form 10-Q for the quarter ended September 30, 2011, File No. 001-09120, on November 1, 2011 and incorporated herein by this reference.
(11)Filed as Exhibit 10a(7) with Annual Report on Form 10-K for the year ended December 31, 2011, File No. 001-09120, on February 27, 2012 and incorporated herein by this reference.
(12)Filed as Exhibit 10 with Quarterly Report on Form 10-Q for the quarter ended September 30, 2002, File No. 001-09120, on November 4, 2002 and incorporated herein by this reference.
(13)Filed as Exhibit 10a(7) with Annual Report on Form 10-K for the year ended December 31, 2000, File No. 001-09120, on March 6, 2001 and incorporated herein by this reference.
(14)Filed as Exhibit 10a(11) with Annual Report on Form 10-K for the year ended December 31, 2008, File No. 001-09120, on February 26, 2009 and incorporated herein by this reference.
(15)Filed as Exhibit 99 with Current Report on Form 8-K, File Nos. 001-09120, 000-49614 and 001-00973, on December 22, 2008 and incorporated herein by this reference.
(16)Filed as Exhibit 10a(17) with Annual Report on Form 10-K for the year ended December 31, 2002, File No. 001-09120, on February 26, 2003 and incorporated herein by this reference.
(17)Filed as Exhibit 10a(20) with Annual Report on Form 10-K for the year ended December 31, 2002, File No. 001-09120, on February 26, 2003 and incorporated herein by this reference.
(18)Filed as Exhibit 10 with Quarterly Report on Form 10-Q for the quarter ended March 31, 2013, File No. 001-09120, on May 1, 2013 and incorporated herein by reference.
(19)Filed as Exhibit 10.1 with Current Report on Form 8-K, File No. 001-09120, on February 19, 2009 and incorporated herein by this reference.
(20)Filed as Exhibit 10a(19) with Annual Report on Form 10-K for the year ended December 31, 2011, File No. 001-09120, on February 27, 2012.
(21)Filed as Exhibit 10 with Quarterly Report on Form 10-Q for the quarter ended September 30, 2011, File No. 001-09120, on November 1, 2011 and incorporated herein by reference.
(22)Filed as Exhibit 10a with Annual Report on Form 10-K for the year ended December 31, 2014, File No. 001-09120, on February 26, 2015.
(23)Filed as Exhibit 10 with Quarterly Report on Form 10-Q for the quarter ended September 30, 2015, File No. 001-09120, on October 30, 2015.
(24)Filed as Exhibit 3(a) with Quarterly Report on Form 10-Q for the quarter ended June 30, 1986, File No. 001-00973, on August 28, 1986 and incorporated herein by this reference.
(25)Filed as Exhibit 3a(2) with Annual Report on Form 10-K for the year ended December 31, 1987, File No. 001-00973, on March 28, 1988 and incorporated herein by this reference.
(26)Filed as Exhibit 3a(3) on Form 8-A, File No. 001-00973, on February 4, 1994 and incorporated herein by this reference.
(27)Filed as Exhibit 3a(4) on Form 8-A, File No. 001-00973, on February 4, 1994 and incorporated herein by this reference.
(28)Filed as Exhibit 3a(5) on Form 8-A, File No. 001-00973, on February 4, 1994 and incorporated herein by this reference.
(29)Filed as Exhibit 3.3 with Quarterly Report on Form 10-Q for the quarter ended March 31, 2007, File No. 001-00973, on May 4, 2007 and incorporated herein by this reference.
(30)Filed as Exhibit 4b(1) with Annual Report on Form 10-K for the year ended December 31, 1980, File No. 001-00973, on February 18, 1981 and incorporated herein by this reference.
(31)Filed as Exhibit 4b(3) with Annual Report on Form 10-K for the year ended December 31, 1980, File No. 001-00973, on February 18, 1981 and incorporated herein by this reference.

(4)Filed as Exhibit 99.1 with Current Report on Form 8-K, File No. 001-09120, on December 16, 2015 and incorporated herein by this reference.
(5)Filed as Exhibit 4(f) with Quarterly Report on Form 10-Q for the quarter ended March 31, 1998, File No. 001-09120, on May 13, 1998 and incorporated herein by this reference.
(6)Filed as Exhibit 4(f) with Annual Report on Form 10-K for the year ended December 31, 1998, File No. 001-09120, on February 23, 1999 and incorporated herein by this reference
(7)Filed as Exhibit 4c for PSEG with Annual Report on Form 10-K for the year ended December 31, 2019. File No. 001-09120, on February 26,2020 and incorporated herein by this reference.
(8)Filed as Exhibit 10.1 with Quarterly Report on Form 10-Q for the quarter ended September 30, 2019, File No. 001-09120, on October 31, 2019 and incorporated herein by this reference.
(9)Filed as Exhibit 10.2 with Quarterly Report on Form 10-Q for the quarter ended September 30, 2019, File No. 001-09120, on October 31, 2019 and incorporated herein by this reference.
(10)Filed as Exhibit 10a(4) with Annual Report on Form 10-K for the year ended December 31, 2018, File No. 001-09120 on February 27, 2019 and incorporated herein by this reference.
(11)Filed as Exhibit 10a(5) with Annual Report on Form 10-K for the year ended December 31, 2018, File No. 001-09120 on February 27, 2019 and incorporated herein by this reference.
(12)Filed as Exhibit 10a(11) with Annual Report on Form 10-K for the year ended December 31, 2008, File No. 001-09120, on February 26, 2009 and incorporated herein by this reference.
(13)Filed as Exhibit 10.3 with Quarterly Report on Form 10-Q for the quarter ended September 30, 2019, File No. 001-09120 on October 31, 2019 and incorporated herein by this reference.
(14)Filed as Exhibit 99 with Current Report on Form 8-K, File Nos. 001-09120, 000-49614 and 001-00973, on December 22, 2008 and incorporated herein by this reference.
(15)Filed as Exhibit 10a(17) with Annual Report on Form 10-K for the year ended December 31, 2002, File No. 001-09120, on February 26, 2003 and incorporated herein by this reference.
(16)Filed as Exhibit 10a(20) with Annual Report on Form 10-K for the year ended December 31, 2002, File No. 001-09120, on February 26, 2003 and incorporated herein by this reference.
(17)Filed as Exhibit 10 with Quarterly Report on Form 10-Q for the quarter ended March 31, 2013, File No. 001-09120, on May 1, 2013 and incorporated herein by this reference.
(18)Filed as Exhibit 10.1 with Current Report on Form 8-K, File No. 001-09120, on February 19, 2009 and incorporated herein by this reference.
(19)Filed as Exhibit 10a(15) with Annual Report on Form 10-K for the year ended December 31, 2018, File No. 001-09120 on February 27, 2019 and incorporated herein by this reference.
(20)Filed as Exhibit 10a with Annual Report on Form 10-K for the year ended December 31, 2014, File No. 001-09120, on February 26, 2015, and incorporated herein by this reference.
(21)Filed as Exhibit 10 with Quarterly Report on Form 10-Q for the quarter ended September 30, 2015, File No. 001-09120, on October 30, 2015, and incorporated herein by this reference.
(22)Filed as Exhibit 10a(20) with Annual Report on Form 10-K for the year ended December 31, 2017, File No. 001-09120 on February 26, 2018 and incorporated herein by this reference.
(23)Filed as Exhibit 10a(19) with Annual Report on Form 10-K for the year ended December 31, 2019, File No. 001-09120, on February 26, 2020 and incorporated herein by this reference.
(24)Filed as Exhibit 3a(1) on Form 8-A, File No. 001-00973, on February 4, 1994 and incorporated herein by this reference.
(25)Filed as Exhibit 3a(2) on Form 8-A, File No. 001-00973, on February 4, 1994 and incorporated herein by this reference.
(26)Filed as Exhibit 3a(3) on Form 8-A, File No. 001-00973, on February 4, 1994 and incorporated herein by this reference.
(27)Filed as Exhibit 3a(4) on Form 8-A, File No. 001-00973, on February 4, 1994 and incorporated herein by this reference.
(28)Filed as Exhibit 3a(5) on Form 8-A, File No. 001-00973, on February 4, 1994 and incorporated herein by this reference.
(29)Filed as Exhibit 3.3 with Quarterly Report on Form 10-Q for the quarter ended March 31, 2007, File No. 001-00973, on May 4, 2007 and incorporated herein by this reference.
(30)Filed as Exhibit 4b(1) with Annual Report on Form 10-K for the year ended December 31, 1980, File No. 001-00973, on February 18, 1981 and incorporated herein by this reference.
(31)Filed as Exhibit 4b(3) with Annual Report on Form 10-K for the year ended December 31, 1980, File No. 001-00973, on February 18, 1981 and incorporated herein by this reference.
191
193

Table of Contents




(32)Filed as Exhibit 4b(4) with Annual Report on Form 10-K for the year ended December 31, 1980, File No. 001-00973, on February 18, 1981 and incorporated herein by this reference.
(33)Filed as Exhibit 4b(6) with Annual Report on Form 10-K for the year ended December 31, 1980, File No. 001-00973, on February 18, 1981 and incorporated herein by this reference.
(34)Filed as Exhibit 4 on Form 8-A, File No. 001-00973, on June 1, 1991 and incorporated herein by this reference.
(35)Filed as Exhibit 4(i) on Form 8-A, File No. 001-00973, on December 1, 1993 and incorporated herein by this reference.
(36)Filed as Exhibit 4a(28) with Annual Report on Form 10-K for the year ended December 31, 2004, File No. 001-00973, on March 1, 2005 and incorporated herein by this reference.
(37)Filed as Exhibit 4a(28) with Annual Report on Form 10-K for the year ended December 31, 2007, File No. 001-00973, on February 28, 2008 and incorporated herein by this reference.
(38)Filed as Exhibit 4a(32) with Annual Report on Form 10-K for the year ended December 31, 2012, File No. 001-00973, on February 26, 2013.
(39)Filed as Exhibit 4a(33) with Annual Report on Form 10-K for the year ended December 31, 2012, File No. 001-00973, on February 26, 2013.
(40)Filed as Exhibit 4 with Quarterly Report on Form 10-Q for the quarter ended June 30, 2013, File No. 001-00973, on July 30, 2013.
(41)Filed as Exhibit 4a(22) with Quarterly Report on Form 10-Q for the quarter ended September 30, 2014, File No. 001-09120, on October 30, 2014 and incorporated herein by reference.
(42)Filed as Exhibit 4a(23) with Quarterly Report on Form 10-Q for the quarter ended June 30, 2015, File No. 001-09120, on July 31, 2015 and incorporated herein by reference.
(43)Filed as Exhibit 4(a)(14) with Annual Report on Form 10-K for the year ended December 31, 2016, File No. 001-00973, on February 27, 2017 and incorporated herein by reference.
(44)Filed as Exhibit 4 with Current Report on Form 8-K, File No. 001-00973, on December 1, 1993 and incorporated herein by reference.
(45)Filed as Exhibit 4.6 to Registration Statement on Form S-3, File No. 333-76020, filed on December 27, 2001 and incorporated herein by reference.
(46)Filed as Exhibit 10.2 with Current Report on Form 8-K, File No. 001-00973, on February 19, 2009 and incorporated herein by reference.
(47)Filed as Exhibit 3.1 to Registration Statement on Form S-4, No. 333-69228, filed on September 10, 2001 and incorporated herein by this reference.
(48)Filed as Exhibit 3.2 to Registration Statement on Form S-4, No. 333-69228, filed on September 10, 2001 and incorporated herein by this reference.
(49)Filed as Exhibit 4.1 to Registration Statement on Form S-4, No. 333-69228, filed on September 10, 2001 and incorporated herein by this reference.
(50)Filed as Exhibit 4.7 with Quarterly Report on Form 10-Q for the quarter ended March 31, 2002, File No. 000-49614, on May 15, 2002 and incorporated herein by this reference.

(32)Filed as Exhibit 4b(4) with Annual Report on Form 10-K for the year ended December 31, 1980, File No. 001-00973, on February 18, 1981 and incorporated herein by this reference.

(33)Filed as Exhibit 4(i) on Form 8-A, File No. 001-00973, on June 1, 1991 and incorporated herein by this reference.
(34)Filed as Exhibit 4a(28) with Annual Report on Form 10-K for the year ended December 31, 2004, File No. 001-00973, on March 1, 2005 and incorporated herein by this reference.
(35)Filed as Exhibit 4a(28) with Annual Report on Form 10-K for the year ended December 31, 2007, File No. 001-00973, on February 28, 2008 and incorporated herein by this reference.
(36)Filed as Exhibit 4a(30) with Annual Report on Form 10-K for the year ended December 31, 2009, File No. 001-00973, on February 25, 2010 and incorporated herein by this reference.
(37)Filed as Exhibit 4a(32) with Annual Report on Form 10-K for the year ended December 31, 2012, File No. 001-00973, on February 26, 2013, and incorporated herein by this reference.
(38)Filed as Exhibit 4 with Quarterly Report on Form 10-Q for the quarter ended June 30, 2013, File No. 001-00973, on July 30, 2013, and incorporated herein by this reference.
(39)Filed as Exhibit 4a(22) with Quarterly Report on Form 10-Q for the quarter ended September 30, 2014, File No. 001-09120, on October 30, 2014 and incorporated herein by this reference.
(40)Filed as Exhibit 4a(23) with Quarterly Report on Form 10-Q for the quarter ended June 30, 2015, File No. 001-09120, on July 31, 2015 and incorporated herein by this reference.
(41)Filed as Exhibit 4a(14) with Annual Report on Form 10-K for the year ended December 31, 2016, File No. 001-00973, on February 27, 2017 and incorporated herein by this reference.
(42)Filed as Exhibit 4a(15) with Quarterly Report on Form 10-Q for the quarter ended March 31, 2018, File No. 001-00973, on April 30, 2018 and incorporated herein by this reference.
(43)Filed as Exhibit 4a(15) with Annual Report on Form 10-K for the year ended December 31, 2019, File No. 001-09120, on February 26, 2020 and incorporated herein by this reference.
(44)Filed as Exhibit 4b with Annual Report on Form 10-K for the year ended December 31, 2019, File No. 001-09120, on February 26, 2020 and incorporated herein by the reference.
(45)Filed as Exhibit 4 with Current Report on Form 8-K, File No. 001-00973, on December 1, 1993 and incorporated herein by this reference.
(46)Filed as Exhibit 4-6 to Registration Statement on Form S-3, File No. 333-76020, filed on December 27, 2001 and incorporated herein by this reference.
(47)Filed as Exhibit 10.2 with Current Report on Form 8-K, File No. 001-00973, on February 19, 2009 and incorporated herein by this reference.
(48)Filed as Exhibit 3.1 to Registration Statement on Form S-4, No. 333-69228, filed on September 10, 2001 and incorporated herein by this reference.
(49)Filed as Exhibit 3.2 to Registration Statement on Form S-4, No. 333-69228, filed on September 10, 2001 and incorporated herein by this reference.
(50)Filed as Exhibit 4.1 to Registration Statement on Form S-4, No. 333-69228, filed on September 10, 2001 and incorporated herein by this reference.
(51)Filed as Exhibit 4.7 with Quarterly Report on Form 10-Q for the quarter ended March 31, 2002, File No. 000-49614, on May 15, 2002 and incorporated herein by this reference.
(52)Filed as Exhibit 4c for PSEG Power with Annual Report on Form 10-K for the year ended December 31, 2019, File No. 001-09120, on February 26, 2020 and incorporated herein by this reference.

192
194



Schedule II—Valuation and Qualifying Accounts Years Ended December 31, 2017—2020—December 31, 20152018
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
Column AColumn BColumn C AdditionsColumn D Column E
DescriptionBalance at
Beginning of
Period		Charged to
cost and
expenses		Charged to
other
accounts-
describe		Deductions-
describe		Balance at
End of
Period
 Millions
2020
Allowance for Credit Losses$68 (D)$175 (A)$0 $37 (B) $206 
Materials and Supplies Valuation Reserve11 1 0 2 (C) 10 
2019
Allowance for Credit Losses$63 $87 (A)$0 $90 (B) $60 
Materials and Supplies Valuation Reserve9 3 0 1 (C) 11 
2018
Allowance for Credit Losses$59 $91 (A)$0 $87 (B) $63 
Materials and Supplies Valuation Reserve7 4 0 2 (C)9��
               
 Column A Column B Column C Additions Column D   Column E 
 Description 
Balance at
Beginning of
Period
 
Charged to
cost and
expenses
 
Charged to
other
accounts-
describe
 
Deductions-
describe
   
Balance at
End of
Period
 
   Millions 
 2017             
    Allowance for Doubtful Accounts $68
 $76
 $—
 $85
 (A)  $59
 
    Materials and Supplies Valuation Reserve 37
 2
 —
 32
 (C)  7
 
 2016             
    Allowance for Doubtful Accounts $67
 $85
 $—
 $84
 (A)  $68
 
    Materials and Supplies Valuation Reserve 11
 32
 —
 6
 (B)  37
 
 2015             
    Allowance for Doubtful Accounts $52
 $101
 $—
 $86
 (A)  $67
 
    Materials and Supplies Valuation Reserve 15
 2
 —
 6
 (B)  11
 
               
(A)For a discussion of bad debt recoveries, see Note 1. Organization, Basis of Presentation and Summary of Significant Accounting Policies.
(A)Accounts Receivable written off.
(B)Reduce reserve to appropriate level and to remove obsolete inventory.
(C)Hudson and Mercer inventory written off.
(B)Accounts Receivable written off.
(C)Reduce reserve to appropriate level and to remove obsolete inventory.
(D)Includes $8 million due to the adoption of ASU 2016-13.
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
Column AColumn BColumn C AdditionsColumn DColumn E
DescriptionBalance at
Beginning
of Period		Charged to
cost and
expenses		Charged to
other
accounts-
describe		Deductions-
describe		Balance at
End of
Period
Millions
2020
Allowance for Credit Losses$68 (C)$175 (A)$0 $37 (B)$206 
Materials and Supplies Valuation Reserve2 0 0 0 2 
2019
Allowance for Credit Losses$63 $87 (A)$0 $90 (B)$60 
Materials and Supplies Valuation Reserve2 0 0 0 2 
2018
Allowance for Credit Losses$59 $91 (A)$0 $87 (B)$63 
Materials and Supplies Valuation Reserve0 2 0 0 2 
               
 Column A Column B Column C Additions Column D   Column E 
 Description 
Balance at
Beginning
of Period
 
Charged to
cost and
expenses
 
Charged to
other
accounts-
describe
 
Deductions-
describe
   
Balance at
End of
Period
 
   Millions 
 2017             
 Allowance for Doubtful Accounts $68
 $76
 $—
 $85
 (A)  $59
 
 Materials and Supplies Valuation Reserve —
 —
 —
 —
   —
 
 2016             
 Allowance for Doubtful Accounts $67
 $85
 $—
 $84
 (A)  $68
 
 Materials and Supplies Valuation Reserve 1
 —
 —
 1
 (B) —
 
 2015             
 Allowance for Doubtful Accounts $52
 $101
 $—
 $86
 (A)  $67
 
 Materials and Supplies Valuation Reserve 2
 —
 —
 1
 (B)  1
 
               
(A)For a discussion of bad debt recoveries, see Note 1. Organization, Basis of Presentation and Summary of Significant Accounting Policies.
(A)Accounts Receivable written off.
(B)Reduce reserve to appropriate level and to remove obsolete inventory.
(B)Accounts Receivable written off.
(C)Includes $8 million due to the adoption of ASU 2016-13.
PSEG POWER LLC
Column AColumn BColumn C AdditionsColumn DColumn E
DescriptionBalance at
Beginning
of Period		Charged to
cost and
expenses		Charged to
other
accounts-
describe		Deductions-
describe		Balance at
End of
Period
   Millions   
2020
Materials and Supplies Valuation Reserve$9 $1 $0 $2 (A) $8 
2019
Materials and Supplies Valuation Reserve$7 $3 $0 $1 (A) $9 
2018
Materials and Supplies Valuation Reserve$7 $2 $0 $2 (A) $7 
(A)Reduce reserve to appropriate level and to remove obsolete inventory.
195
               
 Column A Column B Column C Additions Column D   Column E 
 Description 
Balance at
Beginning
of Period
 
Charged to
cost and
expenses
 
Charged to
other
accounts-
describe
 
Deductions-
describe
   
Balance at
End of
Period
 
       Millions       
 2017             
 Materials and Supplies Valuation Reserve $37
 $2
 $—
 $32
 (A)  $7
 
 2016             
 Materials and Supplies Valuation Reserve $10
 $32
 $—
 $5
 (B)  $37
 
 2015             
 Materials and Supplies Valuation Reserve $13
 $2
 $—
 $5
 (B)  $10
 
               
(A)Hudson and Mercer inventory written off.
(B)Reduce reserve to appropriate level and to remove obsolete inventory.

193



GLOSSARY OF TERMS
When the following terms and abbreviations appear in the text of this report, they have the meanings indicated below:
Term            Phrase/Description
Base loadMinimum amount of electric power delivered or required over a given period of time at a constant rate, this is the level of demand that is seen as a minimum during a 24-hour day
BGSBasic Generation Service
PSE&G is required to provide BGS for all customers in New Jersey who are not supplied by a third-party supplier.
BGS-RSCPBasic Generation Service-Residential Small Commercial Product
Seasonally adjusted fixed prices charged for a three-year term for electric supply service to smaller industrial and commercial customers and residential customers who are not supplied by a TPS
BGSSBasic Gas Supply Service
Mechanism approved by the BPU for NJ utilities to recover all commodity costs related to supplying gas to residential customers
BPUNew Jersey Board of Public Utilities
Agency responsible for regulating public utilities doing business in New Jersey
CapacityAmount of electricity that can be produced by a specific generating facility
Combined CycleA method of generation whereby electricity and process steam are produced from otherwise lost waste heat exiting from one or more combustion turbines. The exiting heat is routed to a conventional boiler or to a heat recovery steam generator for use by a steam turbine in the production of electricity
CongestionCondition when the available capacity of a transmission line is being closely approached (or exceeded) by the electric power trying to go through it; at such times, alternative power line pathways (or local generators near the load) must be used instead
DistributionThe delivery of electricity to the retail customer’s home, business or industrial facility through low voltage distribution lines
EPAU.S. Environmental Protection Agency
FASBFinancial Accounting Standards Board
A private, not-for-profit organization whose primary purpose, as designated by the SEC, is to develop accounting standards for public companies in the U.S.
FERCU.S. Federal Energy Regulatory Commission
Forward contractsA customized, non-exchange traded contract in which the buyer is obligated to deliver a specified amount of a commodity with a predetermined price formula on a specified future date, at which time payment is due in full
GAAPGenerally Accepted Accounting Principles
Standard framework of guidelines issued by the FASB for financial accounting used in the U.S.
GHGGreenhouse gas emissions (including carbon dioxide, methane, nitrous oxide, ozone, and chlorofluorocarbon) that trap the heat of the sun in the Earth’s atmosphere, increasing the mean global surface temperature of the earth
HedgingEntering into a contract or transaction designed to reduce exposure to various risks, such as changes in market prices
ISOIndependent System Operator
An independent, regulated entity established to manage a regional electric transmission system in a non-discriminatory manner and to help ensure the safety and reliability of the bulk of the power system
LoadAmount of electric power delivered or required at any specific point or points on a system. The requirement originates at the energy-consuming equipment of consumers.

194

Term            Phrase/Description
MBRMarket Based Rates
Electric service prices determined in an open market system of supply and demand under which the price is set solely by agreement as to what a buyer will pay and a seller will accept
MGPManufactured Gas Plant
ISO-NENew England Power Pool
An ISO comprised of an alliance of approximately 100 utility companies who manage and direct all major energy production and transmission in the New England states
NJDEPNew Jersey Department of Environmental Protection
NRCU.S. Nuclear Regulatory Commission
NUGNon-Utility Generation
Power produced by independent power producers, exempt wholesale generators and other companies that have been exempted from traditional utility regulation
OPEBOther Postretirement Benefits
Benefits other than pensions payable to former employees
OutageThe period during which a generating unit, transmission line, or other facility is out of service due to scheduled (planned) or unscheduled maintenance
PJMPJM Interconnection, L.L.C.
A regional transmission organization that coordinates the movement of wholesale electricity in all or parts of 13 northeastern states and the District of Columbia
PowerPSEG Power LLC
Power PoolAn association of two or more interconnected electric systems having an agreement to coordinate operations and planning for improved reliability and efficiencies
PSE&GPublic Service Electric and Gas Company
PSEGPublic Service Enterprise Group Incorporated
Renewable EnergyEnergy derived from resources that are regenerative or that cannot be depleted (i.e. moving water (hydro, tidal and wave power), thermal gradients in ocean water, biomass, geothermal energy, solar energy, and wind energy)
Regulatory AssetCosts deferred by a regulated utility company in accordance with Accounting Standards Codification Topic 980: Regulated operations (ASC 980)
Regulatory LiabilityCosts recognized by a regulated utility company in accordance with ASC 980
RPMReliability Pricing Model (PJM market)
A process for pricing generation capacity based on overall system reliability requirements; using multi-year forward auctions, participants could bid capacity in the form of generation, demand response, or transmission to meet reliability needs by location and/or an ISO market
SBCSocietal Benefits Charge
SECU.S. Securities and Exchange Commission
Tax ActComprehensive tax legislation, Public Law 115-97, enacted by the U.S. government in December 2017, which, among other things, decreased the statutory U.S. corporate income tax rate from a maximum of 35% to 21%, effective January 1, 2018, and made certain changes to bonus depreciation rules.
TransmissionThe high-voltage wires and networks that move electricity through states and regions in large quantities - from power plants where it is produced, to the distribution networks that deliver it to homes and businesses


195


SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
By:
/s/ RALPH IZZO
Ralph Izzo
Chairman of the Board, President and
Chief Executive Officer
Date: February 26, 20182021
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signatures of the undersigned shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
SignatureTitleDate
SignatureTitleDate
/s/ RALPH IZZO
Chairman of the Board, President, Chief Executive Officer andFebruary 26, 20182021
Ralph IzzoDirector (Principal Executive Officer)
/s/ DANIEL J. CREGG
Executive Vice President and Chief Financial OfficerFebruary 26, 20182021
Daniel J. Cregg(Principal Financial Officer)
/s/ STUART J. BLACKROSE M. CHERNICK
Vice President and ControllerFebruary 26, 20182021
Stuart J. BlackRose M. Chernick(Principal Accounting Officer)
/s/ WILLIE A. DEESE
DirectorFebruary 26, 20182021
Willie A. Deese
/s/ SHIRLEYALBERT R. GAMPER,NN JR.ACKSON
DirectorFebruary 26, 20182021
Albert R. Gamper, Jr.Shirley Ann Jackson
/s/ WILLIAM V. HICKEYDAVID LILLEY
DirectorFebruary 26, 20182021
William V. HickeyDavid Lilley
/s/ SHIRLEY ANN JACKSONBARRY H. OSTROWSKY
DirectorFebruary 26, 20182021
Shirley Ann JacksonBarry H. Ostrowsky
/s/ DAVID LILLEYSCOTT G. STEPHENSON
DirectorFebruary 26, 20182021
David LilleyScott G. Stephenson
/s/ BARRY H. OSTROWSKYLAURA A. SUGG
DirectorFebruary 26, 20182021
Barry H. OstrowskyLaura A. Sugg
/s/ THOMAS A. RENYIJOHN P. SURMA
DirectorFebruary 26, 20182021
Thomas A. RenyiJohn P. Surma
/s/ HAK CHEOLSHINUSAN TOMASKY
DirectorFebruary 26, 20182021
Hak Cheol ShinSusan Tomasky
/s/ RICHARD J. SWIFTALFRED W. ZOLLAR
DirectorFebruary 26, 20182021
Richard J. Swift
/s/ SUSAN TOMASKY
DirectorFebruary 26, 2018
Susan Tomasky
/s/ ALFRED W. ZOLLAR
DirectorFebruary 26, 2018
Alfred W. Zollar





196







SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
PUBLIC SERVICE ELECTRICAND GAS COMPANY
By:/s/ DAVID M. DALY
David M. Daly
President and Chief Operating Officer


Date: February 26, 20182021
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signatures of the undersigned shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
 
SignatureTitleDate
SignatureTitleDate
/s/ RALPH IZZO
Chairman of the Board and Chief Executive Officer andFebruary 26, 20182021
Ralph IzzoDirector (Principal Executive Officer)
/s/ DANIEL J. CREGG
Executive Vice President and Chief Financial OfficerFebruary 26, 20182021
Daniel J. Cregg(Principal Financial Officer)
/s/ STUART J. BLACKROSE M. CHERNICK
Vice President and ControllerFebruary 26, 20182021
Stuart J. BlackRose M. Chernick(Principal Accounting Officer)
/s/ ALBERT R. GAMPER, JR.DAVID LILLEY
DirectorFebruary 26, 20182021
Albert R. Gamper Jr.David Lilley
/s/ SHIRLEY ANN JACKSON
DirectorFebruary 26, 20182021
Shirley Ann Jackson
/s/ RICHARD J. SWIFTUSAN TOMASKY
DirectorFebruary 26, 20182021
Richard J. SwiftSusan Tomasky







197







SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
PSEG POWER LLC
By:
/s/ RALPH A. LAROSSA
Ralph A. LaRossa
President and Chief Operating Officer


Date: February 26, 20182021
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signatures of the undersigned shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
 
SignatureTitleDate
SignatureTitleDate
/s/ RALPH IZZO
Chairman of the Board and Chief Executive Officer andFebruary 26, 20182021
Ralph IzzoDirector (Principal Executive Officer)
/s/ DANIEL J. CREGG
Executive Vice President and Chief Financial Officer andFebruary 26, 20182021
Daniel J. CreggDirector (Principal Financial Officer)
��
/s/ STUART J. BLACKROSE M. CHERNICK
Vice President and ControllerFebruary 26, 20182021
Stuart J. BlackRose M. Chernick(Principal Accounting Officer)
/s/ DEREK M. DIRISIO
DirectorFebruary 26, 20182021
Derek M. DiRisio
/s/ RALPH A. LAROSSA
DirectorFebruary 26, 20182021
Ralph A. LaRossa
/s/ TAMARA L. LINDE
DirectorFebruary 26, 20182021
Tamara L. Linde
/s/ MARGARET M. PEGOSHEILA ROSTIAC
DirectorFebruary 26, 20182021
Margaret M. PegoSheila Rostiac







198