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,
									2020						2019
									Millions, except per share data
			PSE&G						$	1,327					$	1,250
			PSEG Power						594						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,
									2020						2019						2018
			Earnings (Losses)						Millions
			PSE&G						$	1,327					$	1,250					$	1,067
			PSEG Power (A)						594						468						365
			Other (B)						(16)						(25)						6
			PSEG Net Income						$	1,905					$	1,693					$	1,438
			PSEG Net Income Per Share (Diluted)						$	3.76					$	3.33					$	2.83

(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,						2020						2019						2018
									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,
									2020						2019						2018						2020 vs. 2019									2019 vs. 2018
									Millions																		Millions						%						Millions						%
			Operating Revenues						$	9,603					$	10,076					$	9,696					$	(473)					(5)						$	380					4
			Energy Costs						3,056						3,372						3,225						(316)						(9)						147						5
			Operation and Maintenance						3,115						3,111						3,069						4						—						42						1
			Depreciation and Amortization						1,285						1,248						1,158						37						3						90						8
			(Gain) Loss on Asset Dispositions						(123)						402						(54)						(525)						(131)						456						N/A
			Income from Equity Method Investments						14						14						15						—						—						(1)						(7)
			Net Gains (Losses) on Trust Investments						253						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 Expense						600						569						476						31						5						93						20
			Income Tax (Benefit) Expense						396						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)
									2020						2019						2018						2020 vs. 2019									2019 vs. 2018
									Millions																		Millions						%						Millions						%
			Operating Revenues						$	6,608					$	6,625					$	6,471					$	(17)					—						$	154					2
			Energy Costs						2,469						2,738						2,520						(269)						(10)						218						9
			Operation and Maintenance						1,614						1,581						1,575						33						2						6						—
			Depreciation and Amortization						887						837						770						50						6						67						9
			Gain on Asset Dispositions						(1)						—						—						(1)						N/A						—						—
			Net Gains (Losses) on Trust Investments						3						2						(1)						1						50						3						N/A
			Other Income (Deductions)						108						83						80						25						30						3						4
			Non-Operating Pension and OPEB Credits (Costs)						205						150						59						55						37						91						N/A
			Interest Expense						388						361						333						27						7						28						8
			Income Tax Expense						240						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)
									2020						2019						2018						2020 vs. 2019									2019 vs. 2018
									Millions																		Millions						%						Millions						%
			Operating Revenues						$	3,634					$	4,385					$	4,146					$	(751)					(17)						$	239					6
			Energy Costs						1,821						2,118						2,197						(297)						(14)						(79)						(4)
			Operation and Maintenance						964						1,040						1,053						(76)						(7)						(13)						(1)
			Depreciation and Amortization						368						377						354						(9)						(2)						23						6
			(Gain) Loss on Asset Dispositions						(122)						402						(54)						(524)						N/A						456						N/A
			Income from Equity Method Investments						14						14						15						—						—						(1)						(7)
			Net Gains (Losses) on Trust Investments						241						253						(140)						(12)						(5)						393						N/A
			Other Income (Deductions)						12						54						21						(42)						N/A						33						N/A
			Non-Operating Pension and OPEB Credits (Costs)						33						21						15						12						57						6						40
			Interest Expense						121						119						76						2						2						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

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interests in the Keystone and Conemaugh generation plants in 2019. This was partially offset by higher volumes of electricity sold in the NE region, primarily due to the commencement of commercial operations of Bridgeport Harbor Unit 5 (BH5) in June 2019 and higher volumes of electricity sold in the NY region,

• a decrease of $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

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conditions have adversely impacted residential and C&I customer payment patterns. During the moratorium, PSE&G has experienced a significant decrease in cash inflow and higher Accounts Receivable aging and an associated increase in bad debt expense, which we expect will extend beyond the duration of the coronavirus pandemic. While the impact on our results of operations, financial condition and cash flows for the year ended December 31, 2020 was not material, a prolonged coronavirus pandemic and the associated economic impacts, which could extend beyond the duration of the pandemic, could materially impact cash from operations, Accounts Receivable and bad debt expense.

PSE&G

PSE&G’s operating cash flow decreased $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/Facility						As of December 31, 2020
			Total Facility						Usage						Available Liquidity
									Millions
			PSEG						$	1,500					$	665					$	835
			PSE&G						600						117						483
			PSEG Power						2,100						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 Stock						2020						2019						2018
			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
			Outlook			Stable						Stable
			Senior Notes			Baa1						BBB
			Commercial Paper			P2						A2
			PSE&G
			Outlook			Stable						Stable
			Mortgage Bonds			Aa3						A
			Commercial Paper			P1						A2
			PSEG Power
			Outlook			Stable						Stable
			Senior Notes			Baa1						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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									2021						2022						2023
															Millions
			PSE&G:
			Transmission						$	955					$	890					$	645
			Electric Distribution						695						790						1,055
			Gas Distribution						875						870						985
			Clean Energy						200						375						400
			Total PSE&G						$	2,725					$	2,925					$	3,085
			PSEG Power						100						120						150
			Other						25						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&G						10,999						434						825						1,100						8,640
			PSEG Power						2,348						950						994						—						404
			Interest on Recourse Debt
			PSEG						315						68						105						54						88
			PSE&G						6,650						390						756						683						4,821
			PSEG Power						487						93						132						70						192
			Operating Leases
			PSE&G						127						16						24						18						69
			PSEG Power						89						14						22						6						47
			Services						150						15						30						30						75
			Energy-Related Purchase Commitments
			PSEG Power						2,252						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&G						12						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.

			Assumption						2020						2019						2018
			Pension
			Discount Rate						2.61		%				3.30		%				4.41		%
			Expected Rate of Return on Plan Assets						7.70		%				7.80		%				7.80		%
			OPEB
			Discount Rate						2.46		%				3.20		%				4.31		%
			Expected Rate of Return on Plan Assets						7.70		%				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.

									% Change						Impact on Benefit Obligation as of December 31, 2020						Increase to Costs in 2021						Increase to Costs, net of Amounts Capitalized in 2021
			Assumption												Millions
			Pension
			Discount Rate						(1)%						$	987					$	37					$	26
			Expected Rate of Return on Plan Assets						(1)%						N/A						$	62					$	62
			OPEB
			Discount Rate						(1)%						$	143					$	17					$	16
			Expected Rate of Return on Plan Assets						(1)%						N/A						$	5					$	5

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

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Derivative Instruments

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

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

Assumptions and Approach Used**:** In general, the fair value of our derivative instruments is determined primarily by end of day clearing market prices from an exchange, such as 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.