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PEG Public Service Electric & Gas

Filed: 28 Feb 21, 7:00pm
0000788784pseg:PollutionControlNotesMemberpseg:PSEGPowerLLCMember2020-12-31
    
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
——————————
FORM 10-K
(Mark One)
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED December 31, 2020
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM          TO        
Commission
File Number
Name of Registrant, Address, and Telephone NumberState or other jurisdiction of IncorporationI.R.S. Employer
Identification Number
001-09120  Public Service Enterprise Group IncorporatedNew Jersey22-2625848
80 Park Plaza
Newark,New Jersey07102
973430-7000
001-00973  Public Service Electric and Gas CompanyNew Jersey22-1212800
80 Park Plaza
Newark,New Jersey07102
973430-7000
001-34232  PSEG Power LLCDelaware22-3663480
80 Park Plaza
Newark,New Jersey07102
973430-7000
Securities registered pursuant to Section 12(b) of the Act:
Title of Each ClassTrading Symbol(s)Name of Each Exchange
On Which Registered
Public Service Enterprise Group Incorporated
  Common Stock without par valuePEGNew York Stock Exchange
Public Service Electric and Gas Company
  9.25% First and Refunding Mortgage Bonds, Series CC, due 2021PEG21New York Stock Exchange
  8.00% First and Refunding Mortgage Bonds, due 2037PEG37DNew York Stock Exchange
  5.00% First and Refunding Mortgage Bonds, due 2037PEG37JNew York Stock Exchange
PSEG Power LLC
  8.625% Senior Notes, due 2031PEG31New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None

(Cover continued on next page)


(Cover continued from previous page)
    Indicate by check mark whether each registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
Public Service Enterprise Group IncorporatedYesNo
Public Service Electric and Gas CompanyYesNo
PSEG Power LLCYesNo
    Indicate by check mark if each of the registrants is not required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934. Yes No
    Indicate by check mark whether each of the registrants (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports) and (2) has been subject to such filing requirements for the past 90 days. Yes No
Indicate by check mark whether the registrants have submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrants were required to submit such files) . Yes No
Indicate by check mark whether each registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Public Service Enterprise Group IncorporatedLarge Accelerated FilerAccelerated FilerNon-accelerated FilerSmaller reporting companyEmerging growth company
Public Service Electric and Gas CompanyLarge Accelerated FilerAccelerated FilerNon-accelerated FilerSmaller reporting companyEmerging growth company
PSEG Power LLCLarge Accelerated FilerAccelerated FilerNon-accelerated FilerSmaller reporting companyEmerging growth company
If any of the registrants is an emerging growth company, indicate by check mark if such registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. 
Indicate by check mark whether each of the registrants has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 726(b)) by the registered public accounting firm that prepared and issued its audit report.
Public Service Enterprise Group Incorporated
Public Service Electric and Gas Company
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 No
The aggregate market value of the Common Stock of Public Service Enterprise Group Incorporated held by non-affiliates as of June 30, 2020 was $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 19, 2021 was 505,093,089.
As of February 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 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 2021 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 15, 2021, as specified herein.



TABLE OF CONTENTS
 Page
FORWARD-LOOKING STATEMENTS
FILING FORMAT
WHERE TO FIND MORE INFORMATION
PART I
Item 1.Business
Regulatory Issues
Environmental Matters
Information About Our Executive Officers (PSEG)
Item 1A.Risk Factors
Item 1B.Unresolved Staff Comments
Item 2.Properties
Item 3.Legal Proceedings
Item 4.Mine Safety Disclosures
PART II
Item 5.Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Item 6.Selected Financial Data
Item 7.Management’s Discussion and Analysis of Financial Condition and Results of Operations
Executive Overview of 2020 and Future Outlook
Results of Operations
Liquidity and Capital Resources
Capital Requirements
Off-Balance Sheet Arrangements
Critical Accounting Estimates
Item 7A.Quantitative and Qualitative Disclosures About Market Risk
Item 8.Financial Statements and Supplementary Data
Report of Independent Registered Public Accounting Firm
Consolidated Financial Statements
Notes to Consolidated Financial Statements
Note 1. Organization, Basis of Presentation and Summary of Significant Accounting Policies
Note 2. Recent Accounting Standards
Note 3. Revenues
Note 4. Early Plant Retirements/Asset Dispositions
Note 5. Variable Interest Entity (VIE)
Note 6. Property, Plant and Equipment and Jointly-Owned Facilities
Note 7. Regulatory Assets and Liabilities
Note 8. Leases
Note 9. Long-Term Investments
Note 10. Financing Receivables
Note 11. Trust Investments
Note 12. Goodwill and Other Intangibles
Note 13. Asset Retirement Obligations (AROs)
Note 14. Pension, Other Postretirement Benefits (OPEB) and Savings Plans
Note 15. Commitments and Contingent Liabilities
Note 16. Debt and Credit Facilities
Note 17. Schedule of Consolidated Capital Stock
i

TABLE OF CONTENTS (continued)
Note 18. Financial Risk Management Activities
Note 19. Fair Value Measurements
Note 20. Stock Based Compensation
Note 21. Other Income (Deductions)
Note 22. Income Taxes
Note 23. Accumulated Other Comprehensive Income (Loss), Net of Tax
Note 24. Earnings Per Share (EPS) and Dividends
Note 25. Financial Information by Business Segment
Note 26. Related-Party Transactions
Item 9.Changes In and Disagreements With Accountants on Accounting and Financial Disclosure
Item 9A.Controls and Procedures
Item 9B.Other Information
PART III
Item 10.Directors, Executive Officers and Corporate Governance
Item 11.Executive Compensation
Item 12.Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Item 13.Certain Relationships and Related Transactions, and Director Independence
Item 14.Principal Accounting Fees and Services
PART IV
Item 15.Exhibits, Financial Statement Schedules
Schedule II - Valuation and Qualifying Accounts
Signatures


ii

FORWARD-LOOKING STATEMENTS
Certain of the matters discussed in this report about our and our subsidiaries’ future performance, including, without limitation, future revenues, earnings, strategies, prospects, consequences and all other statements that are not purely historical constitute “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. Such forward-looking statements are subject to risks and uncertainties, which could cause actual results to differ materially from those anticipated. Such statements are based on management’s beliefs as well as assumptions made by and information currently available to management. When used herein, the words “anticipate,” “intend,” “estimate,” “believe,” “expect,” “plan,” “should,” “hypothetical,” “potential,” “forecast,” “project,” variations of such words and similar expressions are intended to identify forward-looking statements. Factors that may cause actual results to differ are often presented with the forward-looking statements themselves. Other factors that could cause actual results to differ materially from those contemplated in any forward-looking statements made by us herein are discussed in Item 1A. Risk Factors, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A), Item 8. Financial Statements and Supplementary Data—Note 15. Commitments and Contingent Liabilities, and other filings we make with the United States Securities and Exchange Commission (SEC), including our subsequent reports on Form 10-Q and Form 8-K. These factors include, but are not limited to:
any inability to successfully develop, obtain regulatory approval for, or construct 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;
market risks impacting the operation of our generating stations;
changes in technology related to energy generation, distribution and consumption and changes in customer usage patterns;
third-party credit risk relating to our sale of generation output and purchase of fuel;
any inability of PSEG Power to meet its commitments under forward sale obligations;
reliance on transmission facilities to maintain adequate transmission capacity for our power generation fleet;
the impact of changes in state and federal legislation and regulations on our business, including PSE&G’s ability to recover costs and earn returns on authorized investments;
iii

PSE&G’s proposed investment programs may not be fully approved by regulators and its capital investment may be lower than planned;
the impact 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;
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.
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.

iv

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

ITEM 1.    BUSINESS
We were incorporated under the laws of the State of New Jersey in 1985 and our principal executive offices are located at 80 Park Plaza, Newark, New Jersey 07102. We principally conduct our business through two direct wholly owned subsidiaries, PSE&G and PSEG Power, 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.

1

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 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.
BUSINESS OPERATIONS AND STRATEGY
PSE&G
Our regulated T&D public utility, PSE&G, distributes electric energy and natural gas to customers within a designated service territory running diagonally across New Jersey where approximately 6.2 million people, or about 70% of New Jersey’s population resides.
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Products and Services
Our utility operations primarily earn margins through the T&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 is set by the BPU as a pass-through, resulting in no margin for our utility operations.
We also earn margins through competitive services, such as appliance repair, in our service territory.
2

In addition to our current utility products and services, we have implemented several programs to invest in regulated solar generation within New Jersey, including:
programs to help finance the installation of solar power systems throughout our electric service area, and
programs to develop, own and operate solar power systems.
We have also implemented a set of energy efficiency programs to encourage conservation and energy efficiency by providing energy and cost-saving measures directly to businesses and families.
How PSE&G Operates
We are a transmission owner in PJM Interconnection, L.L.C. (PJM) and we provide distribution service to 2.3 million electric customers and 1.9 million gas customers in a service area that covers approximately 2,600 square miles running diagonally across New Jersey. We serve the most densely populated, commercialized and industrialized territory in New Jersey, including its six largest cities and approximately 300 suburban and rural communities.
Transmission
We use formula rates for our transmission cost of service and investments. Formula rates provide a method of rate recovery where the transmission owner annually determines its revenue requirements through a fixed formula that 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 11.18% on existing and new transmission investment, while certain investments are entitled to earn an additional incentive rate. 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 spending of $2.5 billion for transmission in 2021-2023 as disclosed in Item 7. MD&A—Capital Requirements.    
Distribution
PSE&G distributes electricity and natural gas to end users in our respective franchised service territories. In October 2018, the BPU issued an Order approving the settlement of our distribution base rate proceeding with new rates effective November 1, 2018. The Order provides for a distribution rate base of $9.5 billion, a 9.60% ROE for our distribution business and a 54% equity component of our capitalization structure. The BPU has also approved a series of PSE&G infrastructure, energy efficiency, electric vehicle and renewable energy investment programs with cost recovery through various clause mechanisms. For a discussion of proposed and approved programs, see Item 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 2020:
% of 2020 Sales
Customer TypeElectricGas
Commercial56%36%
Residential35%60%
Industrial9%4%
Total100%100%
Our customer base has modestly increased since 2016, with electric and gas loads changing as illustrated below:
3

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)Excludes sales from Gas rate classes that do not impact margin, specifically Contract, Non-Firm Transportation, Cogeneration Interruptible and Interruptible Services.
Electric sales declined due to the economic impact of the ongoing coronavirus pandemic (COVID-19) on commercial usage, greater conservation, more energy efficient appliances and increases in solar net metering installations, partially offset by an increase in residential sales due to 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 sales impact margin.
Solar Generation
We have undertaken two major solar initiatives at PSE&G, the Solar Loan Program and the Solar 4 All® Programs. Our Solar Loan Program provides solar system financing to our residential and commercial customers. The loans are repaid with cash or solar renewable energy certificates (SRECs). We sell the SRECs received through periodic auctions and use the proceeds to offset program costs. Our Solar 4 All® Programs invest in utility-owned solar photovoltaic (PV) grid-connected solar systems installed on PSE&G property and third-party sites, including landfill facilities, and solar panels installed on distribution system poles in our electric service territory. We sell the energy from the systems in the PJM wholesale electricity market. In addition, we sell SRECs generated by the projects through the same periodic auction used in the Solar Loan program, the proceeds of which are used to offset program costs.
Supply
Although commodity revenues make up almost 34% of our revenues, we make no margin on the default supply of electricity and gas since the actual costs are passed through to our customers.
All electric and gas customers in New Jersey have the ability to choose their electric energy and/or gas supplier. Pursuant to BPU requirements, we serve as the supplier of last resort for two types of electric and gas customers within our service territory that are not served by another supplier. The first type, which represents about 79% of PSE&G’s load requirements, provides default supply service for smaller C&I customers and residential customers at seasonally-adjusted fixed prices for a three-year term (BGS-Residential Small Commercial Pricing (RSCP)). These rates change annually on June 1 and are based on the average price obtained at auctions in the current year and two prior years. The second type provides default supply for larger customers, with energy priced at hourly PJM real-time market prices for a contract term of 12 months (BGS-Commercial Industrial Energy Pricing).
We procure the supply to meet our BGS obligations through auctions authorized by the BPU for New Jersey’s total BGS requirement. These auctions take place annually in February. 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. Note 15. Commitments and Contingent Liabilities.
PSE&G procures the supply requirements of its default service BGSS gas customers through a full-requirements contract with PSEG Power. The BPU has approved a mechanism designed to recover all gas commodity costs related to BGSS for residential customers. BGSS filings are made annually by June 1 of each year, with 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. Any difference between rates charged under the BGSS contract and rates charged to our residential customers is deferred and collected or refunded through adjustments in future rates. C&I customers that do not select third-party suppliers are also supplied under the BGSS arrangement. These customers are charged a market-based price largely determined by prices for commodity futures contracts.
4

Markets and Market Pricing
Historically, there has been significant volatility in commodity prices. Such fluctuations can have a considerable impact on us since a rising commodity price environment results in higher delivered electric and gas rates for customers. This could result in decreased demand for electricity and gas, increased regulatory pressures and greater working capital requirements as the collection of higher commodity costs from our customers may be deferred under our regulated rate structure. A declining commodity price, on the other hand, would be expected to have the opposite effect.
PSEG Power
Through PSEG Power, we have sought to produce low-cost electricity by efficiently operating our nuclear, 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 revenue 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 or dollars per megawatt hour (MWh).
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 thereafter the contract remains in effect unless terminated by either party with a two-year notice.
Approximately 48% of PSE&G’s peak daily gas requirements is provided from PSEG Power’s firm gas transportation capacity. PSEG Power satisfies the remainder of PSE&G’s requirements from storage contracts, contract peaking supply, liquefied natural gas and propane. Based upon the availability of natural gas beyond PSE&G’s daily needs, PSEG Power sells gas to others and uses it for its generation fleet.
PSEG Power also owns and operates 467 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 which comprises the vast majority of PSEG Power’s operations and financial performance.
5

How PSEG Power’s Generation Operates
Nearly all of our generation capacity is located in the Northeast and Mid-Atlantic regions of the United States in some of the country’s largest and most developed electricity markets. For additional information see Item 2. Properties.
Capacity
As of December 31, 2020, our fuel mix was comprised of 57% gas, 34% nuclear, 4% coal, and 5% oil. Our total generating output in 2020 was approximately 52,900 GWh. PSEG 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 since 2017.
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.
Load Following Units’ operating costs are generally higher per unit of output than for base load units due to the use of higher-cost fuels such as oil and natural gas or lower overall unit efficiency. These units usually have more flexible operating characteristics than base load units which enable them to more easily follow fluctuations in load. They operate less frequently than base load units and derive revenues from energy, capacity and ancillary services.
Peaking Units run the least amount of time 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, enabling some gas-fired generation to displace some 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 gross margins than units with comparatively higher marginal costs.
This method of determining supply and pricing creates a situation where natural gas prices often have a major influence on the price that generators will receive for their output, especially in periods of relatively strong or weak demand. Therefore, changes in the price of natural gas will often translate into changes in the wholesale price of electricity. 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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We 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.
Market wholesale prices may vary by location resulting from congestion or other factors, such as the availability of natural gas from the Marcellus (Leidy) and other shale-gas regions and do not necessarily reflect our contract prices. Forward prices are volatile and there can be no assurance that current forward prices will remain in effect or that we will be able to contract output at these forward prices.
Fuel Supply
Nuclear Fuel Supply—We have long-term contracts for nuclear fuel. These contracts provide for:
purchase of uranium (concentrates and uranium hexafluoride),
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conversion of uranium concentrates to uranium hexafluoride,
enrichment of uranium hexafluoride, and
fabrication of nuclear fuel assemblies.
Gas Supply—Natural gas is the primary fuel for the bulk of our load following and peaking fleet. We purchase gas directly from natural gas producers and marketers. 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 Bethlehem Energy Center (BEC) in New York and hold year-round firm gas transportation to serve the majority of the requirements of Keys Energy Center in Maryland.
We have approximately 2.3 billion cubic feet-per-day of firm transportation capacity and firm storage delivery under contract to meet our obligations under the BGSS contract. This volume includes capacity from the Pennsylvania and Ohio shale gas regions where we purchase the majority of our natural gas. On an as-available basis, this firm transportation capacity may also be used to serve the gas supply needs of our New Jersey generation fleet.
Oil—Oil is used as the primary fuel for one load following steam unit and four combustion turbine peaking units and can be used as an alternate fuel by several load following and peaking units that have a dual-fuel capability. Oil for operations is drawn from on-site storage and is generally purchased on the spot market and delivered by truck or barge.
We expect to be able to meet the fuel supply demands of our customers and our operations. However, the ability to maintain an adequate fuel supply could be affected by several factors not within our control, including changes in prices and demand, curtailments by suppliers, severe weather, environmental regulations, and other factors. For additional information and a discussion of risks, see Item 1A. Risk Factors, Item 7. MD&A—Executive Overview of 2020 and Future Outlook and Item 8. Note 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. 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. 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. Our Bridgeport and New Haven stations operate in Connecticut.
The price of electricity varies by location in each of these markets. Depending on our production and our obligations, these price differentials may increase or decrease our profitability.
Commodity prices, such as electricity, gas, 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 several years, lower wholesale natural gas prices have resulted in lower electric energy prices. This trend has reduced margin on forward sales as we re-contract our expected generation output.
In addition to energy sales, we earn revenue from capacity payments for our generating assets. These payments are compensation for committing our generating units to the ISO for dispatch at its discretion. Capacity payments reflect the value to the ISO of assurance that there will be sufficient generating capacity available at all times to meet system reliability and energy requirements. See Item 7. MD&A—Executive Overview of 2020 and 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, capacity pricing mechanism. This is through the Reliability Pricing Model (RPM) in PJM and the Forward Capacity Market (FCM) in ISO-NE. For additional information regarding FERC actions related to the capacity market construct, see Regulatory Issues—Federal Regulation.
The prices to be received by generating units in PJM for capacity have been set through RPM base residual and incremental auctions and depend upon the zone in which the generating unit is located. For each delivery year, the prices differ in the various areas of PJM, depending on the transfer limitations of the transmission system in each area.
Our PJM generating units are located in several zones. The average capacity prices that PSEG Power expects to receive from the base and incremental auctions which have been completed are disclosed in Item 8. Note 3. Revenues. The price that must be paid by an entity serving load in the various zones is also set through these auctions. These prices can be higher or lower than the prices disclosed in Item 8. Note 3. Revenues due to the import and export capability to and from lower-priced areas.
We have obtained price certainty for our PJM capacity through May 2022 through the RPM pricing mechanism and New England capacity through May 2026 for Bridgeport Harbor Unit 5 and May 2024 for New Haven through the FCM pricing mechanism.
Like PJM and ISO-NE, the NYISO provides capacity payments to its generating units, but unlike the other two markets, the New York market does not provide a forward price signal beyond a six-month auction period.
For additional information on the RPM and FCM markets, as well as on state subsidization through various mechanisms, see Regulatory Issues—Federal Regulation.
Hedging Strategy
To mitigate volatility in our results, we seek to contract in advance for a significant portion of our anticipated electric output, capacity and fuel needs. We seek to sell a portion of our anticipated lower-cost generation over a multi-year forward horizon, normally over a period of two to three years. We believe this hedging strategy increases the stability of earnings.
Among the ways in which we have hedged our output are: (1) sales at PJM West or other nodes corresponding to our generation portfolio and (2) physical load sales as full-requirements contracts. Sales in PJM generally reflect block energy sales at the liquid PJM Western Hub or other basis locations when available and other transactions that seek to secure price certainty for our generation related products.
Although we enter into these hedges to provide price certainty for a large portion of our anticipated generation, there is variability in both our actual output as well as in the effectiveness of our hedges. 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.
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 2021 and a significant portion through 2022.
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 more efficient load following units can 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 availability 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 70% of PSEG Power’s expected gross margin in 2021 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:
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. See Item 8. Note 10. Financing Receivables for additional information.
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 to be 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 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.
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. Under the OSA, PSEG LI acts as LIPA’s agent in performing many of its obligations and in return (a) receives reimbursement for pass-through operating expenditures, (b) receives a fixed management fee and (c) is eligible to receive an incentive fee contingent on meeting established performance metrics. Also, there is an 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. 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. 
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 T&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” to construct projects in our service territory, could result in third-party construction of transmission lines in our area in the future and also allow us to seek opportunities to build in other service territories. These rules continue to evolve so both the extent of the risk within our service territory and the opportunities for our transmission business elsewhere remain difficult to assess. For additional information, see the discussion in Regulatory Issues—Federal Regulation—Transmission Regulation, below.
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. Such capacity could impact market prices and our competitiveness.
Our business is also under competitive pressure due to demand-side management (DSM) and other efficiency efforts aimed at changing the quantity and patterns of usage by consumers which could result in a reduction in load requirements. A reduction in load requirements can also be caused by economic cycles, weather and climate change, municipal aggregation and other customer migration and other factors. In addition, how resources such as demand response and capacity imports are permitted to bid into the capacity markets also affects the prices paid to generators such as PSEG Power in these markets. It is also possible that advances in technology, such as distributed generation and micro grids, will reduce the cost of alternative methods of producing electricity to a level that is competitive with that of most central station electric production. To the extent that additions to the electric transmission system relieve or reduce limitations and constraints in eastern PJM where most of our plants are located, our revenues could be adversely affected. Changes in the rules governing what types of transmission will be built, who is selected to build transmission and who will pay the costs of future transmission could also impact our generation revenues.
Adverse changes in energy industry law, policies and regulation could have significant economic, environmental and reliability consequences. For example, PJM, NYISO and ISO-NE each have capacity markets that have been approved by FERC. FERC regulates these markets and continues to examine whether the market design for each of these three capacity markets is working optimally. Various forums are considering how the competitive market framework can incorporate or be reconciled with state public policies that support particular resources, resource attributes or emerging technologies, whether generators are being sufficiently compensated in the capacity market and whether subsidized resources may be adversely affecting capacity market prices. For information regarding recent actions by FERC relating to capacity market design, see the discussion in Regulatory Issues—Federal Regulation.
Environmental issues, such as restrictions on emissions of carbon dioxide (CO2) and other pollutants, may also have a competitive impact on us to the extent that it becomes more expensive for some of our plants to remain compliant, thus affecting our ability to be a lower-cost provider compared to competitors without such restrictions. In addition, most of our plants, which are located in the Northeast where rules are more stringent, can be at an economic disadvantage compared to our competitors in certain Midwest states.
While it is our expectation that continued efforts may be undertaken by the federal and state governments to preserve the existing base nuclear generating plants, we still believe that pressures from renewable resources will continue to increase.
HUMAN CAPITAL MANAGEMENT
At PSEG, 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 inclusion that supports its employees, customers and the many diverse communities we serve. Fundamental to our 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 drives organizational performance and fosters a culture of collaboration, learning and comfort speaking up where new ideas are welcome and employees feel valued and enhance each other’s performance.
As of December 31, 2020, PSEG employed 12,788 full-time employees, of which 61% are covered by collective bargaining agreements. 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 Disabilities, 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 in our workforce. Our strong relationship with our 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.
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 8. Note 15. Commitments and Contingent Liabilities. In addition, information regarding PSE&G’s specific filings pending before the BPU is discussed in Item 8. Note 7. Regulatory Assets and Liabilities.
Federal Regulation
FERC is an independent federal agency that regulates the transmission of electric energy and natural gas in interstate commerce and the sale of electric energy and natural gas at wholesale pursuant to the FPA and the Natural Gas Act. PSE&G and the generation and energy trading subsidiaries of PSEG Power are public utilities as defined by the FPA. FERC has extensive oversight over such public utilities. FERC approval is usually required when a public utility seeks to: sell or acquire an asset
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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.
Regulation of Wholesale Sales—Generation/Market Issues/Market Power
Under FERC regulations, public utilities that wish to sell power at market rates must receive FERC authorization (market-based rate (MBR) Authority) to sell power in interstate commerce before making power sales. They can sell power at cost-based rates or apply to FERC for authority to make MBR sales. For a requesting company to receive MBR Authority, FERC must first determine that the requesting company lacks market power in the relevant markets and/or that market power in the relevant markets is sufficiently mitigated. Certain PSEG companies are public utilities and currently have MBR Authority.
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 non-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 issued 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 their 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 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 participate in this proceeding.
In May 2020, FERC issued an order approving PJM’s proposal to modify the curves used for pricing reserves with FERC. The reforms include a consolidation of synchronized reserve products, improved use of existing capability for locational reserve needs, better alignment of reserve products in day-ahead and real-time markets, a downward-sloping operating reserve demand curve, and increased penalty factors to ensure use of all supply prior to a reserve shortage. These reforms will be implemented in May 2022.
In January 2020, New Jersey rejoined the Regional Greenhouse Gas Initiative (RGGI). As a result, generating plants operating in New Jersey that emit CO2 emissions will have to procure credits for each ton that they emit. Other PJM states in RGGI are Maryland, Delaware and Virginia and Pennsylvania continues to investigate joining. PJM initiated a process in 2019 to investigate the development of a carbon pricing mechanism 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 2021 and 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.
In December 2019, FERC issued an order establishing new rules for PJM’s capacity market. In this new order, FERC extended the PJM Minimum Offer Price Rule (MOPR), which currently applies to new natural gas-fired generators, to include both new and existing resources that receive or are entitled to receive certain out-of-market payments, with certain exemptions.
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 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 2020, 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 auctions was affected by the MOPR to provide capacity within PJM.
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.
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. The FRR provides a means other than PJM’s capacity auction 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 resource adequacy procurement paradigm and potential alternatives. One of the 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 Capacity Performance mechanism, that provides incentives for performance and that imposes charges for non-performance during times of system stress. We view this mechanism as generally positive for generating resources as providing more robust income streams. However, it also imposes additional financial risk for non-performance.
NYISO—NYISO operates a short-term capacity market that provides a forward price signal only for six months into the future. Various matters pending before FERC could affect the competitiveness of this market and the outcome of these proceedings could result in artificial price suppression unless sufficient market protections are adopted.
Transmission Regulation
FERC has exclusive jurisdiction to establish the rates and terms and conditions of service for interstate transmission. We currently have FERC-approved formula rates in effect to recover the costs of our transmission facilities. Under this formula, rates are put into effect in January of each year based upon our internal forecast of annual expenses and capital expenditures. Rates are subsequently trued up to reflect actual annual expenses and capital expenditures.
Transmission Rate Proceedings and Return on Equity—From time to time, various matters are pending before FERC relating to, among other things, transmission planning, reliability standards and transmission rates and returns, including incentives. Depending on their outcome, any of these matters could materially impact our results of operations and financial condition.
In November 2019, FERC issued an order establishing 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 determine if an existing base ROE is unjust and unreasonable and, if so, what replacement ROE is appropriate. PSE&G joined the PJM Transmission Owners in requesting rehearing of FERC’s order on the grounds that the new methodology is flawed. In May 2020, FERC partially 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 utility’s ROE in future proceedings. We continue to analyze the potential impact of these methodologies.
ROE complaints have been pending before FERC regarding Midcontinent Independent System Operator (MISO) transmission owners, the ISO New England Inc. transmission owners and utilities in other jurisdictions. In addition, over the past few years, several companies have negotiated settlements that have resulted in reduced ROEs.
We are engaged in settlement discussions with the BPU Staff and the New Jersey Division of Rate Counsel (New Jersey Rate
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Counsel) about the level of PSE&G’s base transmission ROE; however, we cannot predict the outcome of these settlement discussions. An adverse change to PSE&G’s base transmission ROE or ROE incentives could be material.
    Compliance
Reliability Standards—Congress has required FERC to put in place, through the North American Electric Reliability Corporation (NERC), national and regional reliability standards to ensure the reliability of the U.S. electric transmission and generation system (grid) and to prevent major system blackouts. As a result, FERC directed NERC to draft a physical security standard intended to further protect assets deemed “critical” to reliability of the grid. In July 2015, FERC issued an order approving NERC’s proposed physical security standard. Under the standard, utilities are required to identify critical substations as well as develop threat assessment plans to be reviewed by independent third parties. In our case, the third-party is PJM. As part of these plans, utilities can decide or be required to build additional redundancy into their systems. This standard supplements the Critical Infrastructure Protection standards that are already in place and that establish physical and cybersecurity protections for critical systems. FERC directed NERC to develop a new reliability standard to provide security controls for supply chain management associated with the procurement of industrial control system hardware, software, and services related to grid operations. FERC approved the supply chain management standard in October 2018, with an implementation date of October 1, 2020. We have documented procedures and implemented new processes to comply with these standards.
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 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 environment. Such regulation involves testing, evaluation and modification of all aspects of plant operation in light of NRC safety and environmental requirements. Continuous demonstration to the NRC that plant operations meet requirements is necessary.
The NRC has the ultimate authority to determine whether any nuclear generating unit may operate. The NRC conducts ongoing reviews of nuclear industry operating experience and may issue or revise regulatory requirements. We are unable to predict the final outcome of these reviews or the cost of any actions we would need to take to comply with any new regulations, including possible modifications to the Salem, Hope Creek and Peach Bottom facilities, but such costs could be material.
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
Our principal state regulator is the BPU, which oversees electric and natural gas distribution companies in New Jersey. We are also subject to various other states’ regulations due to our operations in those states.
Our New Jersey utility operations are subject to comprehensive regulation by the BPU including, among other matters, regulation of retail electric and gas distribution rates and service, the issuance and sale of certain types of securities and compliance matters. PSE&G’s participation in solar 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.
In addition to base rates, we recover certain costs or earn on certain investments pursuant to mechanisms known as adjustment clauses. These clauses permit the flow-through of costs to, or the recovery of investments from, customers related to specific programs, outside the context of base rate proceedings. Recovery of these costs or investments is subject to BPU approval for which we make periodic filings. Delays in the pass-through of costs or recovery of investments under these mechanisms could result in significant changes in cash flow.
New Jersey Energy Master Plan (EMP)—In January 2020, the State of New Jersey released its EMP. While the EMP does not have the force of law and does not impose any obligations on utilities, it outlines current expectations regarding the state’s role in the use, management, and development of energy. The EMP recognizes the goals of New Jersey’s Clean Energy Act of 2018 (the Clean Energy Act) 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 business or results of operations from the EMP or any laws, rules or regulations promulgated as a result thereof, particularly as they may relate to PSEG Power’s nuclear and gas generating stations and PSE&G’s electric transmission and gas distribution assets. We also cannot predict what actions federal government agencies may take in light of the Environmental Protection Agency’s (EPA) Affordable Clean Energy (ACE) rule and other federal initiatives associated with climate change or the impact of any such actions on our business or results of operations.
Concurrently 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 securing incremental capacity for their transportation customers; and economic benefits to residential customers. The proceeding remains open.
BGS Process—In July 2020, the State’s EDCs filed their annual proposal for the conduct of the 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 collect transmission costs from its BGS customers as a supply 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 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 Act, 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,” 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 2020, the BPU approved PSE&G’s rate recovery filing. The BPU is continuing to work with the state’s EDCs to establish the mechanisms for implementing the transition incentive program.
Cybersecurity
In an effort to reduce the likelihood and severity of cybersecurity incidents, we have established a comprehensive cybersecurity program designed to protect and preserve the confidentiality, integrity and availability of our information systems. The Board, 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 cybersecurity protections for critical systems and facilities. These standards are also designed to develop coordination, threat sharing and interaction between utilities and various government agencies regarding potential cyber threats against the nation’s electric grid.
FERC further directed NERC to develop a new reliability standard to provide security controls for supply chain management associated with the procurement of industrial control system hardware, software, and services related to bulk electric system operations. FERC approved the 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 comply with these standards.
State—The BPU requires utilities, including PSE&G, to, among other things, implement a cybersecurity program that defines and implements organizational accountabilities and responsibilities for cyber risk management activities, and establishes policies, plans, processes and procedures for identifying and mitigating cyber risk to critical systems. Additional requirements of this order include, but are not limited to: (i) annually inventorying critical utility systems; (ii) annually assessing risks to critical utility systems; (iii) implementing controls to mitigate cyber risks to critical utility systems; (iv) monitoring log files of critical utility systems; (v) reporting cyber incidents to the BPU; and (vi) establishing a cybersecurity incident response plan and conducting biennial exercises to test the plan. In addition, New York’s Stop Hacks and Improve Electronic Data Security (SHIELD) Act, which became effective in March 2020, requires businesses that own or license computerized data that includes New York State residents’ private information to implement reasonable safeguards to protect that information.
ENVIRONMENTAL MATTERS
We are subject to federal, state and local laws and regulations with regard to environmental matters 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 and Item 8. Note 15. Commitments and Contingent Liabilities.
Air Pollution Control
Our facilities are subject to federal regulation under the Clean Air Act 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 Clean 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, the EPA published Mercury Air Toxics Standards (MATS) for both newly-built and existing electric generating sources under the National Emission Standard for Hazardous Air Pollutants provisions of the 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 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 by the U.S. Supreme Court. The 2016 Supplemental Finding determined that HAPS from existing electric generating units should be regulated and that the environmental and health benefits derived from the reduction in emissions of both HAPS and co-benefit pollutants far outweighed the cost of compliance. Industry participants and various state authorities filed petitions with the D.C. Circuit challenging the EPA’s Supplemental Finding.
In May 2020, the EPA finalized a revised Supplemental Finding that reversed the 2016 Supplemental Finding, concluding that it was not “appropriate and necessary” to regulate HAPS from electric generating sources. However, the EPA retained the emission standards and other requirements of MATS. A major coal mining company filed a lawsuit to force the EPA to vacate MATS. We have filed as intervenors to the coal mining company’s suit to challenge the company’s attempt to vacate MATS. In addition, we have joined a challenge against the EPA’s revised Supplemental Finding in the D.C. Circuit Court. We cannot predict the outcome of this matter.
Climate Change
CO2 Regulation under the Clean Air Act—In June 2019, the EPA issued its final ACE rule as a replacement for the repealed Clean Power Plan, a GHG emission regulation for existing power plants. The ACE rule narrowly defines the “best system of emissions reductions” (BSER) as heat improvements to be applied only to an individual unit, excluding other potential mechanisms to address climate change. In September 2019, a coalition of power companies, including PSEG, filed a Petition for Review of the ACE rule with the D.C. Circuit challenging the EPA’s narrow interpretation of BSER. In January 2021, the D.C. Circuit vacated the ACE rule and remanded the rulemaking to the EPA for further consideration. We cannot predict the outcome of this matter or estimate its impact on our business or results of operations.
RGGI—Certain northeastern states (RGGI States) participate in the RGGI and have state-specific rules in place to enable the RGGI regulatory mandate in each state to cap and reduce CO2 emissions. Generating plants operating in RGGI states that emit CO2 will have to procure credits for each ton that they emit. The post-2020 program cap on regional CO2 emissions for RGGI requires a decline in CO2 emissions in 2021 and each year thereafter, resulting in a 30% reduction in the CO2 emissions cap by 2030.
In June 2019, the NJDEP issued two rules that began New Jersey’s re-entry into RGGI. The first rule established New Jersey’s initial cap on GHG emissions of 18 million tons in 2020. This rule follows the RGGI model rule with a cap that will decline three percent annually through 2030 to a final cap of 11.5 million tons. The second rule established the framework for how credits will be allocated among the New Jersey Economic Development Authority , the BPU and the NJDEP. In April 2020, the state issued a final three-year Strategic Funding Plan that determines how quarterly RGGI credits are to be allocated. New Jersey facilities became subject to RGGI on January 1, 2020. With New Jersey’s re-entry into RGGI, we have generation facilities in four of the RGGI States, specifically New Jersey, New York, Maryland and Connecticut.
New Jersey adopted the Global Warming Response Act in 2007, which calls for stabilizing its GHG emissions to 1990 levels by 2020, followed by a further reduction of greenhouse emissions to 80% below 2006 levels by 2050. To reach this goal, the NJDEP, the BPU, other state agencies and stakeholders are required to evaluate methods to meet and exceed the emission reduction targets, taking into account their economic benefits and costs.
New Jersey Protecting Against Climate Threats (NJ PACT)—In response to a New Jersey Executive Order, the NJDEP has undertaken a regulatory reform effort that is designed to modernize environmental laws, referred to as New Jersey Protecting Against Climate Threats (NJ PACT). When implemented, NJ PACT is expected to result in changes to existing environmental regulation, modernizing air quality and environmental land use regulations that will enable governments, businesses and residents to effectively respond to current climate threats and reduce future climate damages. We continue to assess the potential impact of the NJ PACT, which could have cost implications for construction of new or upgrades to existing utility infrastructure and upgrades of our fossil generation facilities. Such expenditures could materially affect the continued economic viability and/or 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.
The EPA’s Clean Water Act (CWA) Section 316(b) rule establishes requirements for the regulation of cooling water intakes at existing power plants and industrial facilities with a design flow of more than two million gallons of water per day. The EPA requires that the NPDES permits be renewed every five years and that each state Permitting Director manage renewal permits for its respective power generation facilities on a case by case basis. The NJDEP manages the permits under the New Jersey Pollutant Discharge Elimination System program. Connecticut and New York also have permits to manage their respective pollutant discharge elimination system programs.
Hazardous Substance Liability
The production and delivery of electricity and the distribution and manufacture of gas result in various by-products and substances classified by federal and state regulations as hazardous. These regulations may impose liability for damages to the environment from hazardous substances, including obligations to conduct environmental remediation of discharged hazardous substances and monetary payments, regardless of the absence of fault, any contractual agreements between private parties, and the absence of any prohibitions against the activity when it occurred, as well as compensation for injuries to natural resources. Our historic operations and the operations of hundreds of other companies along the Passaic and Hackensack Rivers are alleged by federal and state agencies to have discharged substantial contamination into the Passaic River/Newark Bay Complex. The EPA is also evaluating the Hackensack River, a tributary to Newark Bay, for inclusion in the Superfund program. We no longer manufacture gas.
Site Remediation—The Federal Comprehensive Environmental Response, Compensation and Liability Act of 1980 (CERCLA) and the New Jersey Spill Compensation and Control Act (Spill Act) require the remediation of discharged hazardous substances and authorize the EPA, the NJDEP and private parties to commence lawsuits to compel clean-ups or reimbursement for such remediation. The clean-ups can be more complicated and costly when the hazardous substances are in or under a body of water.
Natural Resource Damages—CERCLA and the Spill Act authorize the assessment of damages against persons who have discharged a hazardous substance, causing an injury to natural resources. Pursuant to the Spill Act, the NJDEP requires persons conducting remediation to address injuries to natural resources through restoration or damages. The NJDEP adopted regulations concerning site investigation and remediation that require an ecological evaluation of potential damages to natural resources in connection with an environmental investigation of contaminated sites.
Fuel and Waste Disposal
Nuclear Fuel Disposal—The federal government has entered into contracts with the operators of nuclear power plants for transportation and ultimate disposal of spent nuclear fuel. Under the Nuclear Waste Policy Act of 1982 (NWPA), nuclear plant owners are required to contribute to a Nuclear Waste Fund to pay for this service. Since May 2014, the United States Department of Energy (DOE) 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-Level Radioactive Waste—As a by-product of their operations, nuclear generation units produce low-level radioactive waste. Such waste includes paper, plastics, protective clothing, water purification materials and other materials. These waste materials are accumulated on site and disposed of at licensed permanent disposal facilities. New Jersey, Connecticut and South Carolina have formed the Atlantic Compact, which gives New Jersey nuclear generators continued access to the Barnwell waste disposal facility which is owned by South Carolina. We believe that the Atlantic Compact will provide for adequate low-level radioactive waste disposal for Salem and Hope Creek through the end of their current licenses including full decommissioning, although no assurances can be given. Low-Level Radioactive Waste is periodically being shipped to the Barnwell site from Salem and Hope Creek. Additionally, there are on-site storage facilities for Salem, Hope Creek and Peach Bottom, which we believe have the capacity for at least five years of temporary storage for each facility.
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INFORMATION ABOUT OUR EXECUTIVE OFFICERS (PSEG)
NameAge as of
December 31,
2020
OfficeEffective Date
First Elected to
Present Position
Ralph Izzo63Chairman of the Board (COB), President and
Chief Executive Officer (CEO) - PSEG
April 2007 to present
COB and CEO - PSE&GApril 2007 to present
COB and CEO - PSEG PowerApril 2007 to present
COB and CEO - Energy HoldingsApril 2007 to present
COB and CEO - ServicesJanuary 2010 to present
Daniel J. Cregg57Executive Vice President (EVP) and Chief Financial Officer (CFO) - PSEGOctober 2015 to present
EVP and CFO - PSE&GOctober 2015 to present
EVP and CFO - PSEG PowerOctober 2015 to present
Ralph A. LaRossa57COB - PSEG Long Island LLCDecember 2020 to present
Chief Operating Officer (COO) - PSEGJanuary 2020 to present
President and COO - PSEG PowerOctober 2017 to present
President and COO - PSE&GOctober 2006 to October 2017
COB - PSEG Long Island LLCOctober 2013 to October 2017
David M. Daly59President - PSE&GOctober 2017 to present
President and COO of PSEG Utilities and Clean Energy Ventures - Services; President - PSE&GJanuary 2020 to December 2020
COB - 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. DiRisio56President - ServicesAugust 2014 to present
Tamara L. Linde56EVP and General Counsel - PSEGJuly 2014 to present
EVP and General Counsel - PSE&GJuly 2014 to present
EVP and General Counsel - PSEG PowerJuly 2014 to present
Rose M. Chernick57VP and Controller - PSEGMarch 2019 to present
VP and Controller - PSE&GMarch 2019 to present
VP and Controller - PSEG PowerMarch 2019 to present
VP-Finance, Corporate Strategy and Planning - ServicesNovember 2017 to March 2019
VP-Finance, Holdings and Corporate Strategy and Planning - ServicesOctober 2015 to November 2017


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ITEM 1A.    RISK FACTORS
The following factors should be considered when reviewing our business. These factors could have a material adverse impact on our business, prospects, financial position, results of operations or cash flows and could cause results to differ materially from those expressed elsewhere in this report.
GENERAL OPERATIONAL AND FINANCIAL RISKS
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 oversight on the part of our employees, other insiders or third parties, whether domestic or foreign sources. A cybersecurity attack may also leverage such information technology to cause disruptions at a third party. Cybersecurity impacts to our operations include:
disruption of the operation of our assets, the fuel supply chain 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 the development, 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 generation costs have not declined similarly.
We may be unable to obtain an adequate fuel supply in the future.
We obtain substantially all of our physical natural gas and nuclear fuel supply from third parties pursuant to arrangements that vary in term, pricing structure, firmness and delivery flexibility. Our fuel supply arrangements must be coordinated with transportation agreements, balancing agreements, storage services and other contracts to ensure that the natural gas and nuclear fuel are delivered to our power plants at the times, in the quantities and otherwise in a manner that meets the needs of our generation portfolio and our customers. We must also comply with laws and regulations governing the transportation of such fuels.
We are exposed to increases in the price of natural gas and nuclear fuel, and it is possible that sufficient supplies to operate our generating facilities profitably may not continue to be available to us. Significant changes in the price of natural gas and nuclear fuel could affect our future results and impact our liquidity needs. In addition, we face risks with regard to the delivery to, and the use of natural gas and nuclear fuel by, our power plants including the following:
transportation may be unavailable if pipeline infrastructure is damaged or disabled;
pipeline tariff changes may adversely affect our ability to, or cost to, deliver such fuels;
creditworthiness of third-party suppliers, defaults by third-party suppliers on supply obligations and our ability to replace supplies currently under contract may delay or prevent timely delivery;
market liquidity for physical supplies of such fuels or availability of related services (e.g. storage) may be insufficient or available only at prices that are not acceptable to us;
variation in the quality of such fuels may adversely affect our power plant operations;
legislative or regulatory actions or requirements, including those related to pipeline integrity inspections, may increase the cost of such fuels;
fuel supplies diverted to residential heating may limit the availability of such fuels for our power plants; and
the loss of critical infrastructure, acts of war or terrorist attacks (including cybersecurity breaches) or catastrophic events such as fires, earthquakes, explosions, floods, severe storms or other similar occurrences could impede the delivery of such fuels.
Our nuclear units have a diversified portfolio of contracts and inventory that provide a substantial portion of our fuel raw material needs over the next several years. However, each of our nuclear units has contracted with a single fuel fabrication services provider, and transitioning to an alternative provider could take an extended period of time. Certain of our other generation facilities also require fuel or other services that may only be available from one or a limited number of suppliers. The availability and price of this fuel may vary due to supplier financial or operational disruptions, transportation disruptions 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.
Although our fuel contract portfolio provides a degree of hedging against these market risks, such hedging may not be effective and future increases in our fuel costs could materially and adversely affect our liquidity, financial condition and results of operations. While our generation runs on a mix of fuels, primarily natural gas and nuclear fuel, an increase in the cost of any particular fuel ultimately used could impact our results of operations.
Operation of our generating stations are subject to market risks that are beyond our control.
Generation output will either be used to satisfy wholesale contract requirements or other bilateral contracts or be sold into competitive power markets. Participants in the competitive power markets are not guaranteed any specified rate of return on their capital investments. Generation revenues and results of operations are dependent upon prevailing market prices for energy, capacity, ancillary services and fuel supply in the markets served. Changes in prevailing market prices could have a material adverse effect on our financial condition and results of operations.
Factors that may cause market price fluctuations include:
increases and decreases in generation capacity, including the addition of new supplies of power as a result of the development of new power plants, expansion of existing power plants or additional transmission capacity;
power transmission or fuel transportation capacity constraints or inefficiencies;
power supply disruptions, including power plant outages and transmission disruptions;
climate change and weather conditions, particularly unusually mild summers or warm winters in our market areas;
seasonal fluctuations;
economic and political conditions that could negatively impact the demand for power;
changes in the supply of, and demand for, energy commodities;
development of new fuels or new technologies for the production or storage of power;
federal and state regulations and actions of the ISOs; and
federal and state power, market and environmental regulation and legislation, including financial incentives for new renewable energy generation capacity that could lead to oversupply.
Our generation business frequently involves the establishment of forward sale positions in the wholesale energy markets on long-term and short-term bases. To the extent that we have produced or purchased energy in excess of our contracted obligations, a reduction in market prices could reduce profitability. Conversely, to the extent that we have contracted obligations in excess of energy we have produced or purchased, an increase in market prices could reduce profitability. If the strategy we utilize to hedge our exposure to these various risks or if our internal policies and procedures designed to monitor the exposure to these various risks are not effective, we could incur material losses. Our market positions can also be adversely affected by the level of volatility in the energy markets that, in turn, depends on various factors, including weather in various geographical areas, short-term supply and demand imbalances, customer migration and pricing differentials at various geographic locations. These risks cannot be predicted with certainty.
Increases in market prices also affect our ability to hedge generation output and fuel requirements as the obligation to post margin increases with increasing prices.
The introduction or expansion of technologies related to energy generation, distribution and consumption and changes in customer usage patterns could adversely impact us.
The power generation business has seen a substantial change in the technologies used to produce power. Newer generation facilities are often more efficient than aging facilities, which may put some of these older facilities at a competitive disadvantage to the extent newer facilities are able to consume the same or less fuel to achieve a higher level of generation output. Federal and state incentives for the development and production of renewable sources of power have facilitated the penetration of competing technologies, such as wind, solar, and commercial-sized power storage. Additionally, the development of DSM and energy efficiency programs can impact demand requirements for some of our markets at certain times during the year. The continued development of subsidized, competing power generation technologies and significant development of DSM and energy efficiency programs could alter the market and price structure for power generation and could result in a reduction in load requirements, negatively impacting our financial condition, results of operations and cash flows. Technological advances driven by federal laws mandating new levels of energy efficiency in end-use electric devices or other improvements in, or applications of, technology could also lead to declines in per capita energy consumption.
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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. These technologies could also result in further declines in commodity prices or demand for delivered energy.
Some or all of these factors could result in a lack of growth or decline in customer demand for electricity or number of customers, and may cause us to fail to fully realize anticipated benefits from significant capital investments and expenditures, which could have a material adverse effect on our financial position, results of operations and cash flows. These factors could also materially affect our results of operations, cash flows or financial positions through, among other things, reduced operating revenues, increased 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.
We are subject to third-party credit risk relating to our sale of generation output and purchase of fuel.
We sell generation output and buy fuel through the execution of bilateral contracts. We also seek to contract in advance for a significant proportion of our anticipated output capacity and fuel needs. These contracts are subject to credit risk, which relates to the ability of our counterparties to meet their contractual obligations to us. Any failure of these counterparties to perform could require PSEG Power to purchase or sell energy or fuel in the wholesale markets at less favorable prices and incur additional losses, which could have a material adverse impact on our results of operations, cash flows and financial position. In the spot markets, we are exposed to the risks of the default sharing mechanisms that exist in those markets, some of which attempt to spread the risk across all participants. Therefore, a default by a third party could increase our costs, which could negatively impact our results of operations and cash flows.
There may be periods when PSEG Power may not be able to meet its commitments under forward sale obligations at a reasonable cost or at all.
A substantial portion of PSEG Power’s base load generation output has been sold forward under fixed price power sales contracts and PSEG Power also sells forward the output from its intermediate and peaking facilities when it deems it commercially advantageous to do so. Our forward sales of energy and capacity assume sustained, acceptable levels of operating performance. This is especially important at our lower-cost facilities. Operations at any of our plants could degrade to the point where the plant has to shut down or operate at less than full capacity. Some issues that could impact the operation of our facilities are:
breakdown or failure of equipment, information technology, processes or management effectiveness;
disruptions in the transmission of electricity;
labor disputes or work stoppages;
fuel supply interruptions;
transportation constraints;
limitations which may be imposed by environmental or other regulatory requirements; and
operator error, acts of war or terrorist attacks (including cybersecurity breaches) or catastrophic events such as fires, earthquakes, explosions, floods, severe storms or other similar occurrences.
Identifying and correcting any of these issues may require significant time and expense. Depending on the materiality of the issue, we may choose to close a plant rather than incur the expense of restarting it or returning it to full capacity.
Because the obligations under most of these forward sale agreements are not contingent on a unit being available to generate power, PSEG Power is generally required to deliver power to the buyer even in the event of a plant outage, fuel supply disruption or a reduction in the available capacity of the unit. To the extent that PSEG Power does not have sufficient lower cost capacity to meet its commitments under its forward sale obligations, PSEG Power would be required to pay the difference between the market price at the delivery point and the contract price. The amount of such payments could be substantial and could have a material adverse effect on our financial condition, results of operations and cash flows.
In addition, as market prices for energy and fuel fluctuate, our forward energy sale and forward fuel purchase contracts could require us to post substantial additional collateral, thus requiring us to obtain additional sources of liquidity during periods when our ability to do so may be limited.
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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 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 proceeding and remain in effect until a new base rate proceeding is filed and concluded. In addition, our utility has received approval for several clause recovery mechanisms, some of which provide for recovery of costs and earn returns on authorized investments. These clause mechanisms require periodic updates to be reviewed and approved by the BPU and are subject to prudency reviews. Inability to obtain fair or timely recovery of all our costs, including a return of, or on, our investments in rates, could have a material adverse impact on our results of operations and cash flows. In addition, if legislative and regulatory structures were to evolve in such a way that PSE&G’s exclusive rights to serve its regulated customers were eroded, its future earnings could be negatively impacted.
In September 2020, the BPU ordered the commencement of a comprehensive affiliate and management audit of PSE&G. The BPU also conducts periodic combined management/competitive service audits of New Jersey utilities related to affiliate standard requirements, competitive services, cross-subsidization, cost allocation and other issues. A finding by the BPU of non-compliance with these requirements could 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 material 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’s proposed investment programs may not be fully approved by regulators, which could result in lower than desired service levels to customers, and actual capital investment by PSE&G may be lower than planned, which would cause lower than anticipated rate base.
PSE&G is a regulated public utility that operates and invests in an electric T&D system and a gas distribution system as well as certain regulated clean energy investments, including solar and energy efficiency within New Jersey. PSE&G invests in capital projects to maintain and improve its existing T&D system and to address various public policy goals and meet customer expectations. Transmission projects are subject to review in the FERC-approved PJM transmission expansion process while distribution and clean energy projects are subject to approval by the BPU. We cannot be certain that any proposed project will be approved as requested or at all. If the programs that PSE&G may file from time to time are only approved in part, or not at all, or if the approval fails to allow for the timely recovery of all of PSE&G’s costs, including a return of, or on, its investment, PSE&G will have a lower than anticipated rate base, thus causing its future earnings to be lower than anticipated. If these programs are not approved, that could also adversely affect our service levels for customers. Further, the BPU could take positions to exclude or limit utility participation in certain areas, such as renewable generation, energy efficiency, electric
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vehicle infrastructure and energy storage, which would limit our relationship with customers and narrow our future growth prospects.
We are subject to comprehensive federal regulation that affects, or may affect, our businesses.
We are subject to regulation by federal authorities. Such regulation affects almost every aspect of our businesses, including management and operations; the terms and rates of transmission services; investment strategies; the financing of our operations and the payment of dividends. Failure to comply with these regulations could have a material adverse impact on our ability to operate our business and could result in fines, penalties or sanctions.
Recovery of wholesale transmission rates—PSE&G’s wholesale transmission rates are regulated by FERC and are recovered through a FERC-approved formula rate. The revenue requirements are reset each year through this formula.
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 owners and utilities in other jurisdictions. Over the past few years, several companies have negotiated settlements that have resulted in reduced ROEs.
We are engaged in settlement discussions with the BPU Staff and the New Jersey Rate Counsel about the level of PSE&G’s base transmission ROE; however, we cannot predict the outcome of these 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 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, increased competition for transmission projects could decrease the value of new investments that would be subject to recovery by PSE&G under its rate base, which could have a material adverse impact on our financial condition and results of operations.
NERC Compliance—NERC, at the direction of FERC, has implemented mandatory NERC Operations and Planning and Critical Infrastructure Protection standards to ensure the reliability of the North American Bulk Electric System, which includes electric transmission and generation systems, and to prevent major system blackouts. NERC Critical Infrastructure Protection standards establish cybersecurity and physical security protections for critical systems and facilities. We have been, and will continue to be, periodically audited by NERC for compliance and are subject to penalties for non-compliance with applicable NERC standards. 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.
MBR Authority and Other Regulatory Approvals—Under FERC regulations, public utilities that wish to sell power at market rates must receive MBR authority before making power sales, and the majority of our businesses operate with such authority. Failure to maintain MBR authorization, or the effects of any severe mitigation measures that 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.
Oversight by the CFTC relating to derivative transactions—The CFTC has regulatory oversight of the swap and futures markets and options, including energy trading, and licensed futures professionals such as brokers, clearing members and large traders. Changes to regulations or adoption of additional regulations by the CFTC, including any regulations relating to futures and other derivatives or margin for derivatives and increased investigations by the CFTC, could negatively impact PSEG Power’s ability to hedge its portfolio in an efficient, cost-effective manner by, among other things, potentially decreasing liquidity in the forward commodity and derivatives markets or limiting PSEG Power’s ability to utilize non-cash collateral for derivatives transactions.
We may also be required to obtain various other regulatory approvals to, among other things, buy or sell assets, engage in transactions between our public utility and our other subsidiaries, and, in some cases, enter into financing arrangements, issue securities and allow our subsidiaries to pay dividends. Failure to obtain these approvals on a timely basis could materially adversely affect our results of operations and cash flows.
Our New Jersey nuclear plants may not be awarded ZECs in future periods, or the current or subsequent ZEC program periods could be materially adversely modified through legal proceedings, either of which could result in the retirement of all of these nuclear plants. 
As 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 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 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. In addition to the risk of retirement discussed below, risks associated with the operation of nuclear facilities include:
Storage and Disposal of Spent Nuclear Fuel—Federal law requires the DOE to provide for the permanent storage of spent nuclear fuel 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 facilities; or the shutdown of one of our nuclear facilities. Any such event could have a material adverse effect on our financial condition or results of operations.
Operational Risk—Operations at any of our nuclear facilities could degrade to the point where an affected unit needs to be shut down or operated at less than full capacity. If this were to happen, identifying and correcting the causes may require significant time and expense. Any significant outages could result in reduced earnings as we would have less electric output to sell.
In addition, if a unit cannot be operated through the end of its current estimated useful life, our results of operations could be adversely affected by increased depreciation rates, impairment charges and accelerated future decommissioning costs.
Nuclear Incident or Accident Risk—Accidents and other unforeseen problems have occurred at nuclear stations, both in the U.S. and elsewhere. The consequences of an accident can be severe and may include loss of life, significant property damage and/or a change in the regulatory climate. We have nuclear units at two sites. It is possible that an accident or other incident at a nuclear generating unit could adversely affect our ability to continue to operate unaffected units located at the same site, which would further affect our financial condition, results of operations and cash flows. An accident or incident at a nuclear unit not owned by us could lead to increased regulation, which could affect our ability to continue to economically operate our units. Any resulting financial impact from a nuclear accident may exceed our resources, including insurance coverages. Further, as a licensed nuclear operator subject to the Price-Anderson Act and a member of a nuclear industry mutual insurance company, PSEG Power is subject to potential retroactive assessments as a result of an industry nuclear incident or retrospective premiums due to adverse industry loss experience and such assessments may be material.
In the event of non-compliance with applicable legislation, regulation and licenses, the NRC may increase 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 available to cover losses that might arise in connection with the operation of our nuclear fleet are limited and may be insufficient to cover any costs we may incur.
Decommissioning—NRC regulations require that licensees of nuclear generating facilities demonstrate reasonable assurance that funds will be available to decommission a nuclear facility at the end of its useful life. PSEG Nuclear has established an NDT Fund to satisfy these obligations. However, forecasting trust fund investment earnings and costs to decommission nuclear generating stations requires significant judgment, and actual results could differ significantly from current estimates. If we determine that it is necessary to retire one of our nuclear generating stations before the end of its useful life, there is a risk that it will no longer meet the NRC minimum funding requirements due to the earlier commencement of decommissioning activities and a shorter time period over which the NDT investments could appreciate in value. A shortfall could require PSEG to post parental guarantees or make additional cash contributions to ensure that the NDT Fund continues to satisfy the NRC minimum funding requirements. As a result, our financial position or cash flows could be significantly adversely affected.
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 of climate change, natural resource damages and other matters. These laws and regulations affect how 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 2020 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. For a further discussion of environmental laws and regulations impacting our business, results of operations and financial condition,
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including the impact of federal and state laws and regulations relating to GHG emissions and remediation of environmental contamination, see Item 1. Environmental Matters and Item 8. Note 15. Commitments and Contingent Liabilities.
We may not receive necessary licenses and permits in a timely manner or at all, which could adversely impact our business and results of operations.
We must periodically apply for licenses and permits from various regulatory authorities, including environmental regulatory authorities, and abide by their respective orders. Delay in obtaining, or failure to obtain and maintain, any permits or approvals, including environmental permits or approvals, or delay in or failure to satisfy any applicable regulatory requirements, could:
prevent construction of new facilities,
limit or prevent continued operation of existing facilities,
limit or prevent the sale of energy from these facilities, or
result in significant additional costs,
each of which could materially affect our business, financial condition, results of operations and cash flows. In addition, the process of obtaining licenses and permits from regulatory authorities may be delayed or defeated by concerted community opposition and such delay or defeat could have a material effect on our business.



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

ITEM 2.    PROPERTIES
All of our owned physical property is held by our subsidiaries. We believe that we and our subsidiaries maintain adequate insurance coverage against loss or damage to plants and properties, subject to certain exceptions, to the extent such property is usually insured and insurance is available at a reasonable cost. For a discussion of nuclear insurance, see Item 8. Note 15. Commitments and Contingent Liabilities.
PSE&G
Primarily all of PSE&G’s property is located in New Jersey and PSE&G’s First and Refunding Mortgage, which secures the bonds issued thereunder, constitutes a direct first mortgage lien on substantially all of PSE&G’s property. PSE&G’s electric lines and gas mains are located over or under public highways, streets, alleys or lands, except where they are located over or under property owned by PSE&G or occupied by it under easements or other rights. PSE&G deems these easements and other rights to be adequate for the purposes for which they are being used.
Electric Property and Facilities
As of December 31, 2020, PSE&G’s electric T&D system included approximately 25,000 circuit miles, and 860,000 poles, of which 64% are jointly-owned. In addition, PSE&G owns and operates 54 switching stations with an aggregate installed capacity of 38,353 megavolt-amperes (MVA) and 245 substations with an aggregate installed capacity of 8,647 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, 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 and three liquid petroleum air gas peaking facilities. The daily gas capacity of these peaking facilities (the maximum daily gas delivery available during the three peak winter months) is approximately 2.5 million therms in the aggregate.
Solar
As of December 31, 2020, PSE&G owned 158 MW dc of installed PV solar capacity throughout New Jersey.
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PSEG Power
Generation Facilities
As of December 31, 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. Note 15. Commitments and Contingent Liabilities.

ITEM 4.    MINE SAFETY DISCLOSURES
Not applicable. 
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PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Our common stock is listed on the New York Stock Exchange, Inc. under the trading symbol “PEG.” As of February 19, 2021, there were 54,220 registered holders.
The following graph shows a comparison of the five-year cumulative return assuming $100 invested on December 31, 2015 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.
 
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 
pseg-20201231_g4.jpg
On February 16, 2021, our Board of Directors approved a $0.51 per share common stock dividend for the first quarter of 2021. This reflects an indicative annual dividend rate of $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.
In December 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 be issued in 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, 2020: 
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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. Note 20. Stock Based Compensation.
PSE&G
We own all of the common stock of PSE&G. For additional information regarding PSE&G’s ability to continue to pay dividends, see Item 7. MD&A—Liquidity and Capital Resources.
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.

ITEM 6. SELECTED FINANCIAL DATA
Omitted pursuant to SEC Release 33-10890.

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 (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 earns it revenues from its portfolio of lease investments and holds our investment in 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 2020 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 2020 AND FUTURE OUTLOOK
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 focuses 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.
Disciplined Investment
We utilize rigorous criteria and consider a number of external factors, focusing on the value for our stakeholders, as well as other impacts, 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 areas that complement our existing business and provide reasonable risk-adjusted returns and continuously assess and optimize our business mix as appropriate. In 2020, we
made additional investments in T&D infrastructure projects on time and on budget,
continued to execute our Energy Efficiency and other existing BPU-approved utility programs,
exercised our option to acquire a 25% 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 PSEG Power’s non-nuclear generation business which is expected to improve our business profile and accelerate our transition to a more regulated electric and gas utility, with a contracted energy business.
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.
ROE complaints have been pending before FERC regarding MISO transmission owners, the ISO New England Inc. transmission owners and utilities in other jurisdictions. In addition, over the past few years, several companies have negotiated settlements that have resulted in reduced ROEs.
We are engaged in settlement discussions with the BPU Staff and the New Jersey Division of Rate Counsel about the level of PSE&G’s base transmission ROE and other 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 PSE&G’s base transmission ROE, and all other factors unchanged, PSE&G’s annual Net Income and annual cash inflows would decrease by approximately $15 million. While we cannot predict the outcome of the 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 December 2019, FERC issued an order 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 under the unit-specific exemption. The MOPR floor prices are not expected to prevent 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 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) alternative service 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 MOPR to provide capacity within PJM. 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.
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 impact 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 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. If the process leads to a market solution, it could have a material impact on the value of PSEG Power’s generating fleet.
Environmental Regulation
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 various statutes. 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. Note 15. Commitments and Contingent Liabilities.
Nuclear
In April 2019, PSEG Power’s Salem 1, Salem 2 and Hope Creek nuclear plants were awarded ZECs by the BPU. Pursuant to a process established by the BPU, ZECs are purchased from selected nuclear plants and recovered through a non-bypassable distribution charge in the amount of $0.004 per kilowatt-hour used (which is equivalent to approximately $10 per megawatt
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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 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. We cannot predict the outcome of this matter.
In the event that (i) the ZEC program is overturned or is otherwise materially adversely modified through legal process; (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 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 these plants would result in a material adverse impact on PSEG’s and PSEG Power’s results of operations.
Nuclear Refueling Outage
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 upgrades were also completed as 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 July 2020, the Internal Revenue Service (IRS) issued final and proposed regulations addressing the limitation on deductible business interest expense contained in the Tax Cuts and Jobs Act (Tax Act). These regulations retroactively allow depreciation to be added back in computing the 30% adjusted taxable income (ATI) cap, increasing the amount of interest that can be deducted by unregulated businesses in years before 2022. For 2022 and after, the regulations continue to disallow the addback of depreciation in the computation of ATI, effectively lowering the cap on the amount of deductible business interest. The portion of PSEG’s and PSEG Power’s business interest expense that was disallowed in 2018 and 2019 will now be deductible in those respective years.
In March 2020, the federal Coronavirus Aid, Relief, and Economic Security Act (CARES Act) was enacted. The CARES Act allows a five-year carryback of any net operating loss (NOL) generated in a taxable year beginning after December 31, 2017 and before January 1, 2021. 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 business interest that can be deducted in a
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given year. Any amount that is disallowed can be carried forward indefinitely. Amounts recorded under the Tax Act and the CARES Act, such as depreciation and business interest disallowance, are subject to change based on 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 to its income tax laws, including requiring corporate taxpayers to file in a combined reporting group as defined under New Jersey law starting in 2019. This provision includes an exemption for public utilities. We believe PSE&G meets the definition of a public utility and, therefore, will not be included in the combined reporting group. Any further guidance or clarification could impact PSEG’s and PSEG Power’s financial statements.
Future Outlook    
Our future success will depend on our ability to continue to maintain strong operational and financial performance to capitalize on or otherwise address regulatory and legislative developments that impact our business and to respond to the issues and challenges described below. In order to do this, we 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 customer satisfaction and complying with applicable standards and requirements,
deliver on our Human Capital Management strategy to attract, develop and retain a diverse, high-performing workforce,
successfully manage our energy obligations and re-contract our open supply positions in response to changes in prices and demand, mindful of the cost and affordability impacts to our electric and gas distribution customers,
advocate for the continuation of the ZEC program to preserve New Jersey’s largest zero-carbon generation resource and measures to ensure the implementation by PJM, FERC and state 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 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, and
manage the risks and opportunities in environmental, social and governance (ESG) matters, which is an integral part of our long-term strategy to be a clean energy leader for the benefit of all stakeholders.
In addition to the risks described elsewhere in this Form 10-K for 2021 and beyond, the key issues and challenges we expect our business to confront include:
regulatory and political uncertainty, both with regard to future energy policy, design of energy and capacity markets, transmission policy and environmental regulation, as well as with respect to the outcome of any legal, regulatory or other proceedings,
the continuing impact of the ongoing coronavirus pandemic and the associated economic impact, which could extend beyond the duration of the pandemic,
the continuing impacts of the Tax and CARES Acts and future changes in federal and state tax laws, and
the impact of changes in demand, natural gas and electricity prices, increasing environmental compliance costs, and expanded efforts to decarbonize several sectors of the economy.
We continually assess a broad range of strategic options to maximize long-term stockholder value and address the interests of our multiple stakeholders. In assessing our options, we consider a wide variety of factors, including the performance and prospects of our businesses; the views of 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:
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investments in T&D facilities to enhance reliability, resiliency and modernize the system to meet the growing needs and increasingly higher expectations of customers, and clean energy investments such as CEF-EE, CEF-EV and CEF-ES,
the disposition or restructuring of our merchant generation business or portions thereof or other existing businesses or the acquisition or development of new businesses,
investments in offshore wind with long-term contracts that provide predictability and a reasonable risk-adjusted return,
continued operations of our nuclear generation facilities, to the extent there is sufficient certainty that their operation will render an acceptable risk-adjusted return, and
acquisitions, dispositions and other transactions involving assets or businesses that could provide value to customers and shareholders.
There can be no assurance, however, that we will successfully develop and execute any of the strategic options noted above, or any additional options we may consider in the future. The execution of any such strategic plan may not have the expected benefits or may have unexpected adverse consequences.

RESULTS OF OPERATIONS
 Years Ended December 31,
202020192018
Earnings (Losses)Millions
 PSE&G$1,327 $1,250 $1,067 
PSEG Power (A)594 468 365 
Other (B)(16)(25)
PSEG Net Income$1,905 $1,693 $1,438 
PSEG Net Income Per Share (Diluted)$3.76 $3.33 $2.83 
 
(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.
(B)Other includes after-tax activities at the parent company, PSEG LI and Energy Holdings as well as intercompany eliminations.
PSEG Power’s results above include the Nuclear Decommissioning Trust (NDT) Fund activity and the impacts of non-trading commodity MTM activity, which consist of the financial impact from positions with future delivery dates.
The variances in our Net Income attributable to changes related to the NDT Fund and MTM are shown in the following table:
Years Ended December 31,202020192018
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 recorded in Other Income (Deductions), interest accretion expense on PSEG Power’s nuclear Asset Retirement Obligation (ARO) recorded in Operation & Maintenance (O&M) Expense and the depreciation related to the ARO asset recorded in Depreciation and Amortization (D&A) Expense.
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(B)Net of tax (expense) benefit of $(94) million, $(103) million and $54 million for the years ended December 31, 2020, 2019 and 2018, respectively.
(C)Net of tax (expense) benefit of $23 million, $(80) million and $33 million for the years ended December 31, 2020, 2019 and 2018, respectively.
Our 2020 year-over-year increase of $212 million in Net Income was driven primarily by
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 the sale of PSEG Power’s interests in the Keystone and Conemaugh fossil generation plants (see Item 8. Note 4. Early Plant Retirements/Asset Dispositions),
higher earnings due to investments in T&D programs at PSE&G, and
higher pension and OPEB credits,
partially offset by MTM losses in 2020 as compared to significant gains in 2019 at PSEG Power, and
a decrease at PSEG Power due to lower average realized prices on lower volumes of electricity sold in PJM and under the BGS contracts, as well as lower capacity revenues, partially offset by a net decrease in fuel costs and recognition of a full year of ZEC revenues in 2020 which commenced in April 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. Note 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 
Energy Costs3,056 3,372 3,225 (316)(9)147 
Operation and Maintenance3,115 3,111 3,069 — 42 
Depreciation and Amortization1,285 1,248 1,158 37 90 
(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 93 20 
Income Tax (Benefit) Expense396 257 417 139 54 (160)(38)
The 2020, 2019 and 2018 amounts in the preceding table for Operating Revenues and O&M costs each include $520 million, $490 million and $458 million, respectively, for PSEG LI’s subsidiary, Long Island Electric Utility Servco, LLC (Servco). These amounts represent the O&M pass-through costs for the Long Island operations, the full reimbursement of which is reflected in Operating Revenues. See Item 8. Note 5. Variable Interest Entity for further explanation. 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)
2020201920182020 vs. 20192019 vs. 2018
 MillionsMillions%Millions%
Operating Revenues$6,608 $6,625 $6,471 $(17)— $154 
Energy Costs2,469 2,738 2,520 (269)(10)218 
Operation and Maintenance1,614 1,581 1,575 33 — 
Depreciation and Amortization887 837 770 50 67 
Gain on Asset Dispositions(1)— — (1)N/A— — 
Net Gains (Losses) on Trust Investments(1)50 N/A
Other Income (Deductions)108 83 80 25 30 
Non-Operating Pension and OPEB Credits (Costs)205 150 59 55 37 91 N/A
Interest Expense388 361 333 27 28 
Income Tax Expense240 93 344 147 N/A(251)N/A
Year Ended December 31, 2020 as compared to 2019
Operating Revenues decreased $17 million due to changes in delivery, clause, commodity and other operating revenues.
Delivery Revenues increased $219 million.
Transmission revenues increased $119 million due to higher revenue requirements calculated through our transmission formula rate, primarily to recover required investments.
Gas distribution revenues increased $4 million due to an increase of $30 million from collection of the GSMP in base rates and an increase in WNC revenues of $19 million. These increases were partially offset by a $44 million decrease from lower sales volumes and $1 million in lower collections of Green Program Recovery Charges (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 GPRC.
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 TAC and GPRC Deferrals, SBC, MAC and SPRC collections were entirely offset by the amortization of related costs (Regulatory Assets) in O&M, D&A and Interest and Tax Expenses. PSE&G does not earn margin on TAC or GPRC deferrals or on SBC, MAC or SPRC collections.
Commodity Revenues decreased $344 million due to lower Gas revenues and lower Electric revenues. The changes in Commodity Revenues for both gas and electric are entirely offset by changes in Energy Costs. PSE&G earns no margin on the provision of basic gas supply service (BGSS) and BGS to retail customers.
Gas revenues decreased $195 million due primarily to lower BGSS sales volumes of $98 million and lower BGSS prices of $94 million.
Electric revenues decreased $149 million due to $161 million from lower prices, partially offset by $12 million of higher BGS sales volumes.
Other Operating Revenues increased $78 million due to increases of $42 million in ZEC revenues and $33 million in SREC revenues. The changes in ZEC revenues and SREC revenues are entirely offset by changes to Energy Costs.
Operating Expenses
Energy Costs decreased $269 million. This is entirely offset by changes in Commodity Revenues and Other Operating Revenues.
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Operation and Maintenance increased $33 million due primarily to increases of $14 million in gas distribution maintenance costs, $13 million in vegetation management, $9 million in transmission maintenance expenditures, $7 million in storm-related costs and $4 million in distribution corrective and preventative maintenance expenditures. These increases were partially offset by a $4 million decrease in injuries and damages and a $10 million reduction in other operating expenses.
Depreciation and Amortization increased $50 million due primarily to an increase in depreciation of $45 million due to additional plant placed into service and a $4 million increase from the amortization of regulatory assets and software.
Other Income (Deductions) increased $25 million due primarily to an 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 $27 million due primarily to increases of $23 million and $12 million due to net long-term debt issuances in 2020 and 2019, respectively. These increases were partially offset by reductions of $7 million in interest expense related to short-term borrowings and in AFUDC.
Income Tax Expense increased $147 million due primarily to the reduction in the 2020 flowback of excess deferred income tax liabilities, higher pre-tax 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, 2019 as compared to 2018
See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations in our 2019 Annual Report.
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 
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 
(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 40 
Interest Expense121 119 76 43 57 
Income Tax Expense (Benefit)188 203 66 (15)(7)137 N/A
Year Ended December 31, 2020 as compared to 2019
Operating Revenues decreased $751 million due to changes in generation, gas supply and other operating revenues.
Generation Revenues decreased $613 million due primarily to
a net decrease of $369 million due to MTM losses in 2020 as compared to MTM gains in 2019. 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
49

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 $79 million in electricity sold under our BGS contracts primarily due to lower volumes coupled with lower prices, and
a net decrease of $56 million in capacity revenues due primarily to decreases in auction prices in the PJM region coupled with lower volumes due to the sale of our ownership interests in Keystone and Conemaugh generation plants,
partially offset by an increase of $70 million due to ZEC revenues that started in April 2019 coupled with increased generation at the nuclear plants in 2020.
Gas Supply Revenues decreased $138 million due primarily to
a decrease of $153 million in sales under the BGSS contract, of which $99 million was due to a decrease in sales volumes and $54 million to lower average sales prices,
partially offset by a net increase of $18 million related to sales to third parties, of which $80 million was due to higher volumes sold, partially offset by $62 million due to lower 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 $297 million due to
Generation costs decreased $156 million due primarily to
a net decrease of $176 million in fuel costs reflecting lower gas prices in the PJM and NY regions coupled with 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
a net decrease of $5 million due to less MTM losses in 2020 as compared to 2019,
partially offset by a net increase of $24 million in higher emission costs primarily due to New Jersey reentering the RGGI program beginning in 2020.
Gas costs decreased $141 million due primarily to
a decrease of $160 million related to sales under the BGSS contract, of which $80 million was due to a decrease in the average cost of gas and $80 million to a decrease in send out volumes. Included in the average cost of gas were $18 million of interstate gas pipeline refunds due to a settlement on pipeline rates from prior periods,
partially offset by a net increase of $18 million related to sales to third parties, of which $73 million was due to higher volumes sold, partially offset by $55 million due to a decrease in the average cost of gas.
Operation and Maintenance decreased $76 million due primarily to a net decrease at our fossil plants due to the sale of our ownership interests in the Keystone and Conemaugh 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 2020.
Depreciation and Amortization decreased $9 million due primarily to an 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 the 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 $17 million of lower capitalized interest in 2020 as a result of BH5 being placed into service in 2019, partially offset by a decrease of $15 million due to debt maturities in April 2020.
Income Tax Expense decreased $15 million due primarily to the benefit of 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 settlement of the 2011-2016 federal income tax audits, partially offset by higher pre-tax income.
Year Ended December 31, 2019 as compared to 2018
See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations in our 2019 Annual Report.
LIQUIDITY AND CAPITAL RESOURCES
The following discussion of our liquidity and capital resources is on a consolidated basis, noting the uses and contributions, where material, of our two direct major operating subsidiaries.
Financing Methodology
We expect our capital requirements to be met through internally generated cash flows and external financings, consisting of short-term debt for working capital needs and long-term debt for capital investments.
PSE&G’s sources of external liquidity include a $600 million multi-year revolving credit facility. PSE&G uses internally generated cash flow and its commercial paper program to meet seasonal, intra-month and temporary working capital needs. PSE&G does not engage in any intercompany borrowing or lending arrangements. PSE&G maintains back-up facilities in an amount sufficient to cover the commercial paper and letters of credit outstanding. PSE&G’s dividend payments to/capital contributions from PSEG are consistent with its capital structure objectives which have been established to maintain investment grade credit ratings. PSE&G’s long-term financing plan is designed to replace maturities, fund a portion of its capital program and manage short-term debt balances. Generally, PSE&G uses either secured medium-term notes or first mortgage bonds to raise long-term capital.
PSEG, PSEG Power, Energy Holdings, PSEG LI and Services participate in a corporate money pool, an aggregation of daily cash balances designed to efficiently manage their respective short-term liquidity needs. Servco does not participate in the corporate money pool. Servco’s short-term liquidity needs are met through an account funded and owned by LIPA.
PSEG’s available sources of external liquidity may include the issuance of long-term debt securities and the incurrence of additional indebtedness under credit facilities. Our current sources of external liquidity include multi-year revolving credit facilities totaling $1.5 billion. These facilities are available to back-stop PSEG’s commercial paper program, issue letters of credit and for general corporate purposes. PSEG’s credit facilities and the commercial paper program are available to support PSEG working capital needs or to temporarily fund growth opportunities in advance of obtaining permanent financing. PSEG’s credit facilities are also available to make equity contributions or provide liquidity 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) or Moody’s. PSEG Power’s dividend payments to PSEG are also designed to be consistent with its capital structure objectives which have been established to maintain investment grade credit ratings and provide sufficient financial flexibility. 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 dividends.
For the year ended December 31, 2020, our operating cash flow decreased by $277 million. The net decrease was primarily due to the net changes from our subsidiaries, as discussed 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
51

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 $82 million from $2,035 million to $1,953 million for the year ended December 31, 2020, as compared to 2019, due primarily to tax payments in 2020 as compared to tax refunds in 2019, increased regulatory deferrals and higher Accounts Receivable reflecting lower collections due to the economic impacts of the pandemic and the moratorium on collections, partially offset by higher earnings and decreases in electric energy and vendor payables.
    PSEG Power
PSEG Power’s operating cash flow decreased $368 million from $1,479 million to $1,111 million for the year ended December 31, 2020, as compared to 2019, due to a $359 million reduction resulting from a modest increase in counterparty cash collateral posting requirements in 2020 as compared to a significant reduction in postings in 2019, and tax payments in 2020 as compared to tax refunds in 2019, partially offset by higher earnings and a $51 million increase from net collections of counterparty 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, 2020 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 
As of December 31, 2020, our credit facility capacity was in excess of our projected maximum liquidity requirements over our 12 month planning horizon, including access to capital to meet redemptions. Our maximum liquidity requirements are based on stress scenarios that incorporate changes in commodity prices and the potential impact of PSEG Power losing its investment grade credit rating from S&P or Moody’s, which would represent a 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 $840 million and $974 million as of December 31, 2020 and 2019, respectively.
For additional information, see Item 8. Note 16. Debt and Credit Facilities.
Long-Term Debt Financing
During the next twelve months,
PSEG has $300 million of 2.00% Senior Notes maturing in November 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 2020, see Item 8. Note 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, 2020, PSE&G’s Mortgage coverage ratio was 3.3 to 1 and the Mortgage would permit up to approximately $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, 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-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” 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
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 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 had accumulated 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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On February 16, 2021, our Board of Directors approved a $0.51 per share common stock dividend for the first quarter of 2021. This reflects an indicative annual dividend rate of $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. 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 Issuer Credit Ratings 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 August 2020, S&P lowered PSEG Power’s Senior Note rating to BBB from BBB+.
Moody’s (A)S&P (B)
PSEG
OutlookStable Stable
Senior NotesBaa1BBB
Commercial PaperP2 A2
PSE&G
OutlookStable Stable
Mortgage BondsAa3 A
Commercial PaperP1 A2
PSEG Power
OutlookStable Stable
Senior NotesBaa1 BBB
(A)Moody’s ratings range from Aaa (highest) to C (lowest) for long-term securities and P1 (highest) to NP (lowest) for short-term securities.
(B)S&P ratings range from AAA (highest) to D (lowest) for long-term securities and A1 (highest) to D (lowest) for short-term securities.
Other Comprehensive Loss
For the year ended December 31, 2020, we had an Other Comprehensive Loss of $15 million on a consolidated basis. The Other Comprehensive Loss was due primarily to a decrease of $46 million related to pension and other postretirement benefits, partially offset by $25 million of net unrealized gains related to Available-for-Sale Securities, and $6 million of unrealized gains on derivative contracts accounted for as hedges. See Item 8. Note 23. Accumulated Other Comprehensive Income (Loss), Net of Tax for additional information.
CAPITAL REQUIREMENTS
We expect that all of our capital requirements over the next three years will come from a combination of internally generated funds and external debt financing. Projected capital construction and investment expenditures, excluding nuclear fuel purchases, for the next three years are presented in the following table. These projections include AFUDC 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 PSE&G include currently approved programs. We intend to continue to invest in infrastructure modernization and will seek to extend these and related programs as appropriate. 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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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 T&D systems to meet expected growth and to manage reliability. As project scope and cost estimates develop, PSE&G will modify its current projections to include these required investments. PSE&G’s projected expenditures for the various items reported above are primarily comprised of the following:
Transmission—investments focused on reliability improvements and replacement of aging infrastructure.
Electric and Gas Distribution—investments for new business, reliability improvements, flood mitigation, and modernization and replacement of equipment that has reached the end of its useful life.
Clean Energy—investments associated with grid-connected solar, customer energy efficiency programs, and infrastructure supporting electric vehicles.
In September 2020, the BPU issued an Order approving our CEF-EE program, authorizing PSE&G to commit $1 billion over a three-year period, with the majority of the investment occurring 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 invest $166 million over what is expected to be a six-year period. See Executive Overview of 2020 and Future Outlook for additional information.
In 2020, PSE&G made $2,507 million of capital expenditures, primarily for T&D system reliability. This does not include expenditures for cost of removal, net of salvage, of $106 million, which are included in operating cash flows.
    PSEG Power
PSEG Power’s projected expenditures are primarily comprised of investments to replace major parts and enhance operational performance.
In 2020, PSEG Power made $195 million of capital expenditures, excluding $209 million for nuclear fuel, primarily related to various nuclear and 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. Note 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. Note 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 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— — — — — 
OFF-BALANCE SHEET ARRANGEMENTS
PSEG and PSEG Power issue guarantees, primarily in conjunction with certain of PSEG Power’s energy contracts. See Item 8. Note 15. Commitments and Contingent Liabilities for further discussion.
CRITICAL ACCOUNTING ESTIMATES
Under accounting guidance generally accepted in the United States (GAAP), many accounting standards require the use of estimates, variable inputs and assumptions (collectively referred to as estimates) that are subjective in nature. Because of this, differences between the actual measure realized versus the estimate can have a material impact on results of operations, financial position and cash flows. We have determined that the following estimates are considered critical to the application of rules that relate to the respective businesses.
Accounting for Pensions and Other Postretirement Benefits (OPEB)
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 and OPEB plans is equal to the fair value of these assets as of year-end. The plan assets are comprised of investments in both debt and equity securities which are valued using quoted market prices, broker or dealer quotations, or alternative pricing sources with reasonable levels of price transparency. Plan assets also include investments in
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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, as well as projected health care costs for OPEB.
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.
We utilize a corridor approach that reduces the volatility of reported costs/credits. The corridor requires differences between actuarial assumptions and plan results be deferred and amortized as part of the costs/credits. This occurs only when the accumulated differences exceed 10% of the greater of the benefit obligation or the fair value of plan assets as of each year-end. For the Pension Plan, the excess would be amortized over the average remaining expected life of inactive participants, which is approximately nineteen years. For Pension Plan II, the excess would be amortized over the average remaining service period of active employees, which is approximately fourteen years.
Effect if Different Assumptions Used: As part of the business planning process, we have modeled future costs assuming a 7.70% expected rate of return and a 2.61% discount rate for 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 costs/credits and funding levels will depend on future investment performance, changes in discount rates, market conditions, funding levels relative to our projected benefit obligation and accumulated benefit obligation and various other factors related to the populations participating in the pension plans. Actual future OPEB costs/credits will depend on future investment performance, changes in discount rates, market conditions, and various other factors.
The following chart reflects the sensitivities associated with a change in certain assumptions. The effects of the assumption changes shown below solely reflect the impact of that specific assumption.
% 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$$
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 the New York Mercantile Exchange, Intercontinental Exchange and Nodal Exchange, or auction prices. Fair values of other energy contracts may be based on broker quotes.
For a small number of contracts where limited observable inputs or pricing information are available, modeling techniques are employed in determination of their fair value using assumptions reflective of contractual terms, current market rates, forward price curves, discount rates and risk factors, as applicable.
For our wholesale energy business, many of the forward sale, forward purchase, option and other contracts are derivative instruments that hedge commodity price risk, but do not meet the requirements for, or are not designated as, either cash flow or fair value hedge accounting. The changes in value of such derivative contracts are marked to market through earnings as the related commodity prices fluctuate. As a result, our earnings may experience significant fluctuations depending on the volatility of commodity prices.
Effect if Different Assumptions Used: Any significant changes to the fair market values of our derivatives instruments could result in a material change in the value of the assets or liabilities recorded on our Consolidated Balance Sheets and could result in a material change to the unrealized gains or losses recorded in our Consolidated Statements of Operations.
For additional information regarding Derivative Financial Instruments, see Item 8. Note 1. Organization, Basis of Presentation and Summary of Significant Accounting Policies, Note 18. Financial Risk Management Activities and Note 19. Fair Value Measurements.
Long-Lived Assets
Management evaluates long-lived assets for impairment and reassesses the reasonableness of their related estimated useful lives whenever events or changes in circumstances warrant assessment. Such events or changes in circumstances may be as a result of significant adverse changes in regulation, business climate, counterparty credit worthiness, market conditions, or a determination that it is more-likely-than-not that an asset or asset group will be sold or retired before its estimated useful life, an asset group’s carrying amount may not be 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, the cost of borrowing and asset sale prices and probabilities associated with any potential sale prior to the end of the estimated useful life or the early retirement of assets. The assumptions used by management incorporate inherent uncertainties that are at times difficult to predict and could result in impairment charges or accelerated depreciation in future periods if actual results materially differ from the estimated assumptions utilized in our forecasts.
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 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
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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 accelerated depreciation. For additional information on the potential impacts on our future financial statements that may be caused by a change in the assumptions noted above, see Item 8. Note 4. Early Plant Retirements/Asset Dispositions.
Asset Retirement Obligations (ARO)
PSE&G, PSEG Power and Services recognize liabilities for the expected cost of retiring long-lived assets for which a legal obligation exists. These AROs are recorded at fair value in the period in which they are incurred and are capitalized as part of the carrying amount of the related long-lived assets. PSE&G, as a rate-regulated entity, recognizes Regulatory Assets or Liabilities as a result of timing differences between the recording of costs and costs recovered through the rate-making process. We accrete the ARO liability to reflect the passage of time with the corresponding expense recorded in O&M Expense.
Assumptions and Approach Used: Because quoted market prices are not available for AROs, we estimate the initial fair value of an ARO by calculating discounted cash flows that are dependent upon various assumptions, including:
estimation of dates for retirement, which can be dependent on environmental and other legislation,
amounts and timing of future cash expenditures associated with retirement, settlement or remediation activities,
discount rates,
cost escalation rates,
market risk premium,
inflation rates, and
if applicable, past experience with government regulators regarding similar obligations.
We obtain updated cost studies triennially unless new information necessitates more frequent updates. The most recent cost study was done in 2018. When we revise any assumptions used to calculate fair values of existing AROs, we adjust the ARO balance and corresponding long-lived asset which generally impacts the amount of accretion and depreciation expense recognized in future periods.
Nuclear Decommissioning AROs
AROs related to the future decommissioning of PSEG Power’s nuclear facilities comprised 95% or $852 million of PSEG Power’s total AROs as of December 31, 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,
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SAFSTOR alternative, which assumes the nuclear facility can be safely stored and subsequently decommissioned in a period within 60 years after operations,
DECON alternative, which assumes decommissioning activities begin after operations, and
recovery from the federal government of 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. Had 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 $33 million increase in the Nuclear ARO.
An increase of 1% in the inflation rate would result in a $292 million increase in the Nuclear ARO.
If we were not reimbursed by the federal government for spent fuel costs as prescribed under the Nuclear Waste Policy Act, the Nuclear ARO would increase by $399 million.
If we would elect or be required to decommission under a DECON alternative at Salem and Hope Creek, the Nuclear ARO would increase by $710 million.
If PSEG Power were to increase its early shutdown probability to 100% and retires Salem 1 and Hope Creek starting in 2022 and Salem 2 in 2023, which is significantly earlier than the end of their current license periods, the Nuclear ARO would increase by $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 Assets and Regulatory Liabilities are supported by BPU orders. In the absence of an order, PSE&G will consider the following when determining whether to record a Regulatory Asset or Liability:
past experience regarding similar items with the BPU,
treatment of a similar item in an order by the BPU for another utility,
passage of new legislation, and
recent discussions with the BPU.
All deferred costs are subject to prudence reviews by the BPU. When the recovery of a Regulatory Asset or payment of a Regulatory Liability is no longer probable, PSE&G charges or credits earnings, as appropriate.
Effect if Different Assumptions Used: A change in the above assumptions may result in a material impact on our results of operations or our cash flows. See Item 8. Note 7. Regulatory Assets and Liabilities for a description of the amounts and nature of regulatory balance sheet amounts.

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-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 31,20202019
95% Confidence Level, Loss could exceed VaR one day in 20 days
Period End$16 $
Average for the Period$10 $12 
High$18 $35 
Low$$
99.5% Confidence Level, Loss could exceed VaR one day in 200 days
Period End$24 $14 
Average for the Period$16 $19 
High$29 $54 
Low$$
See Item 8. Note 18. Financial Risk Management Activities for a discussion of credit risk.
Interest Rates
We are subject to the risk of fluctuating interest rates in the normal course of business. We manage interest rate risk by targeting a balanced debt maturity profile which limits refinancing in any given period or interest rate environment. In addition, we use a mix of fixed and floating rate debt, interest rate swaps and interest rate lock agreements.
As of December 31, 2020, a hypothetical 10% increase in market interest rates would result in
no material impact on annual interest costs related to either the current or the long-term portion of long-term debt, and
a $357 million decrease in the fair value of debt, including a $16 million decrease at PSEG, a $328 million decrease at PSE&G and a $13 million decrease at PSEG Power.
Debt and Equity Securities
We have $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, 2020, the portfolio included $1.4 billion of equity securities and $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, 2020, a hypothetical 10% change in the equity market would impact the value of the equity securities in the NDT Fund by approximately $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 6.22 years and a yield of 1.14%. The portfolio’s value will appreciate or depreciate by the duration with a 1% change in interest rates. As of December 31, 2020, a hypothetical 1% increase in interest rates would result in a decline in the market value for the fixed income portfolio of approximately $71 million.


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

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, 2020 and 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, 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, 2020 and 2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 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), the Company's internal control over financial reporting as of December 31, 2020, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated February 26, 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
66

(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, 2021

We have served as the Company's auditor since 1934.
67

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

Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Public Service Electric and Gas Company and subsidiaries (the “Company” or PSE&G) as of December 31, 2020 and 2019, 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, 2020, 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, 2020 and 2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 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) 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.
69

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, 2021

We have served as the Company's auditor since 1934.
70

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

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, 2020 and 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, 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, 2020 and 2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 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) 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
72

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, 2021

We have served as the Company's auditor since 2000.
73



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 

See Notes to Consolidated Financial Statements.

74

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Millions

 
 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, respectively(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.



75

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 Sale30 
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 Receivable150 
Long-Term Receivable of Variable Interest Entity945 813 
Rabbi Trust Fund266 246 
Other Intangibles158 149 
Derivative Contracts24 
Other286 286 
Total Noncurrent Assets8,835 8,655 
TOTAL ASSETS$50,050 $47,730 
 See Notes to Consolidated Financial Statements.

76

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONSOLIDATED BALANCE SHEETS
Millions
 
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 Contracts
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.
77

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONSOLIDATED STATEMENTS OF CASH FLOWS
Millions
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 
Repayment of Short-Term Loans(500)
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.
78

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
Millions
 
 
 Common
Stock
 Treasury
Stock
Retained
Earnings
Accumulated
Other
Comprehensive
Income (Loss)
  Shs.Amount Shs.AmountTotal
Balance as of December 31, 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)(910)
Other — 19 (1)(45)(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)(950)
Other 23 (23)
Balance as of December 31, 2019 534 $5,003 (30)$(831)$11,406 $(489)$15,089 
Net Income — — — — 1,905 — 1,905 
Other Comprehensive Income (Loss), net of tax (expense) benefit of $0— — — — — (15)(15)
Comprehensive Income 1,890 
Cumulative Effect Adjustment for Current Expected Credit Losses (CECL) — — — — (2)— (2)
Cash Dividends at $1.96 per share on Common Stock — — — — (991)(991)
Other 28 (30)(2)
Balance as of December 31, 2020 534 $5,031  (30)$(861)$12,318 $(504)$15,984 
See Notes to Consolidated Financial Statements.


79


PUBLIC SERVICE ELECTRIC AND GAS COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
Millions
 
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)
Total Operating Expenses4,969 5,156 4,865 
OPERATING INCOME1,639 1,469 1,606 
Net Gains (Losses) on Trust Investments(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.

80

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

 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, respectively(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.

81

PUBLIC SERVICE ELECTRIC AND GAS COMPANY
CONSOLIDATED BALANCE SHEETS
Millions
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 Companies
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.


82

PUBLIC SERVICE ELECTRIC AND GAS COMPANY
CONSOLIDATED BALANCE SHEETS
Millions
 
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 Taxes115 
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)
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.
83

PUBLIC SERVICE ELECTRIC AND GAS COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
Millions 
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)
     Prepayments21 (9)14 
Accounts Payable44 (59)64 
     Accounts Receivable/Payable—Affiliated Companies, net80 203 (139)
     Other Current Assets and Liabilities60 62 
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 (5)
Other12 10 
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 
Cash Dividend Paid(175)(250)
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.


84


PUBLIC SERVICE ELECTRIC AND GAS COMPANY
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER’S EQUITY
Millions
Common StockContributed
Capital
Basis
Adjustment
Retained
Earnings
Accumulated
Other
Comprehensive
Income (Loss)
Total
Balance as of December 31, 2017$892 $1,095 $986 $6,861 $$9,834 
Net Income— — — 1,067  1,067 
Other Comprehensive Income (Loss), net of tax (expense) benefit of $1— — — — (1)(1)
Comprehensive Income1,066 
Balance as of December 31, 2018$892 $1,095 $986 $7,928 $(1)$10,900 
Net Income— — — 1,250  1,250 
Other Comprehensive Income (Loss), net of tax (expense) benefit of $(1)— — — — 
Comprehensive Income1,253 
Cash Dividends Paid— — — (250)— (250)
Balance as of December 31, 2019$892 $1,095 $986 $8,928 $$11,903 
Net Income— — — 1,327  1,327 
Other Comprehensive Income (Loss), net of tax (expense) benefit of $0— — — — 
Comprehensive Income1,328 
Cumulative Effect Adjustment for CECL   (2) (2)
Cash Dividends Paid— — — (175) (175)
Contributed Capital— 75 — — — 75 
Balance as of December 31, 2020$892 $1,170 $986 $10,078 $$13,129 
See disclosures regarding Public Service Electric and Gas Company included in the Notes to Consolidated Financial Statements.

85


PSEG POWER LLC
CONSOLIDATED STATEMENTS OF OPERATIONS
Millions
 
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.


86

PSEG POWER LLC
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Millions
 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.

87

PSEG POWER LLC
CONSOLIDATED BALANCE SHEETS
Millions
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 Sale28 
Other
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 Contracts24 
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.

88

PSEG POWER LLC
CONSOLIDATED BALANCE SHEETS
Millions
 
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 
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 Contracts
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.


89

PSEG POWER LLC
CONSOLIDATED STATEMENTS OF CASH FLOWS
Millions
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)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)(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 
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)
Other42 50 39 
Net Cash Provided By (Used In) Investing Activities(348)(761)(1,051)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of Long-Term Debt700 
Cash Dividend Paid(350)(525)(400)
Redemption of Long-Term Debt(406)(250)
Short-Term Loan from Affiliate(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 Cash(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.


90

PSEG POWER LLC
CONSOLIDATED STATEMENTS OF MEMBER’S EQUITY
Millions
 
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 Di