Item 2. 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. PSEG Power’s subsidiaries are subject to regulation by FERC, the Nuclear Regulatory Commission (NRC), the Environmental Protection Agency (EPA) and the states in which they operate.

PSEG’s other direct wholly owned subsidiaries are: PSEG Long Island LLC (PSEG LI), which operates the Long Island Power Authority’s (LIPA) 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 Part I, Item 1. Business of our 2020 Annual Report on 10-K (Form 10-K) 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 Part I, Item 1A. Risk Factors of Form 10-K provides information about factors that could have a material adverse impact on our businesses. The following supplements that discussion and the discussion included in the Executive Overview of 2020 and Future Outlook provided in Item 7 in our Form 10-K by describing significant events and business developments that have occurred during 2021 and changes to the key factors that we expect may drive our future performance. The following discussion refers to the Condensed Consolidated Financial Statements (Statements) and the Related Notes to Condensed Consolidated Financial Statements (Notes). This discussion should be read in conjunction with such Statements, Notes and the Form 10-K.

EXECUTIVE OVERVIEW OF 2021 AND FUTURE OUTLOOK

We are progressing on our strategy to become a predominantly regulated electric and gas utility and a contracted carbon-free energy infrastructure company. We are focused on meeting customer expectations and being well aligned with public policy objectives by investing to modernize our infrastructure, improve reliability, increase energy efficiency and deliver cleaner energy. Our business plan focuses on achieving growth while controlling costs and managing the risks associated with regulatory and policy changes, 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, which improves the sustainability and predictability of our earnings and cash flows and provides more financial flexibility. In June 2021, we completed the sale of PSEG Power’s solar portfolio and in August 2021 we entered into two agreements to sell PSEG Power’s more than 6,750 megawatts (MW) of fossil generation located in New Jersey, Connecticut, New York and Maryland. See Item 1. Note 4. Early Plant Retirements/Asset Dispositions and Impairments for additional information.

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

The COVID-19 pandemic and associated government actions and economic effects continue to impact our businesses. We have incurred additional expenses to protect our employees and customers, and PSE&G is experiencing significantly higher bad debts and lower cash collections, as discussed below. The potential future impact of the pandemic and the associated economic

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impacts, which could extend beyond the duration of the pandemic, will depend on a number of factors outside of our control. These include the duration and severity of the outbreak as well as third-party actions taken to contain its spread and mitigate its public health effects, and governmental or regulatory actions regarding customer collections, potential limitations on rate increases, recovery of incremental costs, and other matters. While we currently cannot estimate the potential impact to our results of operations, financial condition and cash flows, this MD&A includes a discussion of potential effects of a prolonged outbreak.

PSE&G

At PSE&G, our focus is on enhancing reliability and resiliency of our T&D system, meeting customer expectations and supporting public policy objectives by investing capital in T&D infrastructure and clean energy programs. For the five-year period ending December 31, 2025, PSE&G has increased its expected investments by $1 billion, resulting in a range of $14 billion to $16 billion, which strengthens our expected compound annual growth in rate base of 6.5% to 8%. The low end of the range assumes an extension of our Gas System Modernization Program (GSMP) and Clean Energy Future (CEF)-Energy Efficiency (EE) program at their average annual investment levels, as these programs are expected to continue at least at those current rates beyond their currently approved timeframe of 2023. The upper end of the range is driven by certain unapproved investment programs, including an Infrastructure Advancement Program (IAP) which we plan to file with the BPU in the fourth quarter. The IAP is expected to be an approximate $848 million investment made over four years to improve the reliability of the “last mile” of our electric distribution system, address aging substations and gas metering and regulating stations and invest in electric vehicle charging infrastructure at our facilities to support the electrification of our fleet over the coming years. The upper end of the range also includes an extension of our Energy Strong program, which otherwise concludes in 2023, as well as the remaining portion of our CEF proposal (portion of Electric Vehicle (EV) and Energy Storage (ES) programs) and a potentially higher amount of investment for GSMP and CEF-EE beyond current levels.

In January 2020, New Jersey released its Energy Master Plan (EMP) which, among other things, recognized 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 parties in the CEF-EE proceeding, which the BPU approved. The settlement commits $1 billion over a three-year period, with the majority of the investment occurring over a five-year period. Costs will be recovered through annual rate-making, with returns aligned with our most recent base rate case and a ten-year amortization period.

The approval also included a Conservation Incentive Program (CIP), a mechanism that 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 became effective in June 2021 for electric and October 2021 for gas. PSE&G suspended its gas Weather Normalization Charge (WNC) when the Gas CIP began.

In January 2021, the BPU approved a settlement with PSE&G and other parties in the CEF-Energy Cloud (EC) proceeding. The capital cost of the program, which 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. A remaining component of our program related to medium and heavy duty charging infrastructure has been the subject of a stakeholder process at the BPU this year. We currently anticipate that this effort will conclude by year end, and will inform PSE&G as to the manner by which it should pursue seeking BPU approval of medium and heavy duty charging infrastructure investments, which may include requiring PSE&G to amend its open CEF-EV filing.

All of the capital costs and expenses of the CEF-EC and CEF-EV programs are expected to be recovered in PSE&G’s next base rate case, expected 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 as part of our next rate case expected to be concluded in 2024. Our CEF-ES program is being held in abeyance pending future policy guidance from the BPU.

We also continue to invest in transmission infrastructure in order to (i) maintain and enhance system integrity and grid reliability, (ii) ensure system resilience in the face of continued extreme weather conditions and cyber and physical security threats, (iii) address an aging transmission infrastructure, (iv) leverage technology to improve the operation of the system, (v) reduce transmission constraints, (vi) meet changing customer usage patterns and the demand for 24/7 electricity, and (vii) satisfy state public policy goals, including aggressive decarbonization agendas. Our planned capital spending for transmission in 2021-2023 is $2.6 billion. As discussed further below, in October 2021, FERC approved PSE&G’s settlement with the BPU

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and the New Jersey Division of Rate Counsel (New Jersey Rate Counsel) regarding several amendments to our transmission formula rate, including the reduction of its base transmission return on equity (ROE) from 11.18% to 9.9%.

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

The coronavirus has also impacted PSE&G’s sales, with a reduction in demand from its commercial and industrial (C&I) customers, largely offset by increases in residential sales volumes. As a result, there has been no substantive net margin impact and changes are now largely addressed through the CIP mechanism that became effective in 2021. The most substantive impact of the pandemic on our financial position has been adverse changes to residential and C&I payment patterns. The State of New Jersey issued an Executive Order in March 2020 that included a moratorium on non-safety related service disconnections for non-payment. On June 30, 2021, the moratorium imposed by the State of New Jersey ended but the State has established a “grace period” prohibiting disconnections for residential customers through December 31, 2021. Given the annual winter moratorium on residential shut-offs, collections and shut-offs will not be in full effect until mid-March 2022. During the moratorium, PSE&G has experienced a significant decrease in cash inflow and higher Accounts Receivable aging and an associated increase in bad debt expense, which we expect will continue through the grace period and winter moratorium and take the next several years to fully return to normal levels. PSE&G’s electric distribution bad debt expense is recoverable through its Societal Benefits Clause (SBC) mechanism. PSE&G has deferred its incremental gas distribution bad debt expense as a result of COVID-19 as a Regulatory Asset and will seek recovery of that cost, as well as other net incremental COVID-19 costs, in its next base rate case.

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. In September 2021, the BPU extended the authorization to defer such costs through December 31, 2022. Deferred costs are to be offset by any federal or state assistance that the utility may receive as a direct result of the COVID-19 pandemic. As of September 30, 2021, PSE&G has recorded a Regulatory Asset related to COVID-19 to defer incremental costs of $95 million, which PSE&G expects are probable of recovery under the BPU order. While we expect to continue to defer and ultimately recover these costs under the July BPU Order, no assurances can be given.

PSEG Power

In July 2020, we announced that we were exploring strategic alternatives for PSEG Power’s non-nuclear generating fleet with the intention of accelerating the transformation of our business into a predominantly regulated electric and gas utility, with a significantly contracted generation business. It is expected to reduce overall business risk and earnings volatility, improve PSEG’s financial flexibility and is consistent with PSEG’s climate strategy and sustainability efforts, which are to focus on clean energy investments, methane reduction, and the transition to carbon-free generation. PSEG intends to retain ownership of PSEG Power’s existing nuclear fleet. See Item 1. Note 4. Early Plant Retirements/Asset Dispositions and Impairments for additional information.

In May 2021, PSEG Power Ventures LLC (Power Ventures), a direct wholly owned subsidiary of PSEG Power, entered into a purchase agreement with Quattro Solar, LLC, an affiliate of LS Power, relating to the sale by Power Ventures of 100% of its ownership interest in PSEG Solar Source LLC (Solar Source) including its related assets and liabilities. The transaction closed in June 2021.

In August 2021, PSEG entered into two agreements to sell PSEG Power’s 6,750 MW fossil generating portfolio to newly formed subsidiaries of Arclight Energy Partners Fund VII LP, a fund controlled by ArcLight Capital Partners, LLC. The transactions are expected to be completed late in the fourth quarter of 2021 or the first quarter of 2022. See Item 1. Note 4. Early Plant Retirements/Asset Dispositions and Impairments for further information.

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. In the first nine months of 2021, our natural gas and nuclear units generated 16.7 and 23.6 terawatt hours and operated at a capacity factor of 49.0% and 93.0%, 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 75% 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. While this limits our exposure to decreasing prices, our ability to realize benefits from rising market prices, as experienced in the third quarter of 2021, is also limited. As a result of significantly rising energy prices, during the third quarter of 2021 PSEG Power experienced a substantial increase in net cash collateral postings related to hedge positions that are out-of-the-money from $343 million at the end of June to $999 million at the end of September. Subsequent to the end of September, collateral postings continued to increase and as a result, in October, PSEG Power borrowed $755 million

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from its credit facility to support its Senior Notes redemption and additional collateral postings, as needed. As of the end of October, PSEG Power’s collateral postings were approximately $1.3 billion. PSEG Power continues to maintain sufficient liquidity as described in Liquidity and Capital Resources.

As discussed further below under “Wholesale Power Market Design,” in July 2021, PJM submitted to FERC a proposal to replace the current Minimum Offer Price Rule (MOPR), which applies to both new and existing resources that receive out-of-market payments, with new provisions that accommodate state public policy programs that do not attempt to set the price of capacity. Under the PJM proposal, PSEG Power’s New Jersey nuclear plants that receive ZEC payments would not be subject to the new MOPR. PJM’s proposal requested that FERC approve the new provisions for the Reliability Pricing Model (RPM) auction that was scheduled to be held in December 2021. In September 2021, FERC issued a notice that it was not able to act on PJM’s proposed changes to the MOPR because of a split among the Commissioners on the lawfulness of the proposal. Therefore, PJM’s rules became automatically effective as of September 29, 2021 and will apply to the next base residual auction, which has been delayed until January 25, 2022.

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 the State’s electric service providers’, including PSEG LI’s, preparation and response to the storm. The DPS issued an interim storm investigation report finding that PSEG LI violated its Emergency Response Plan and DPS Regulations, and recommended that LIPA consider taking various actions, including terminating or renegotiating the OSA. LIPA also issued a report with recommendations for improvements to PSEG LI’s structure and processes and recommended that LIPA either renegotiate or terminate the OSA.

In December 2020, LIPA filed a complaint against PSEG LI in New York State court alleging multiple breaches of the OSA in connection with PSEG LI’s preparation for and response to Tropical Storm Isaias seeking specific performance and $70 million in damages. In June 2021, LIPA and PSEG LI executed a non-binding term sheet, which is expected to guide amendments to our OSA. The term sheet includes several changes to the OSA, including shifting a portion of our fixed revenues to incentive compensation and subjecting a portion of revenue to the potential imposition of penalties by the DPS due to certain performance failures by PSEG LI, and resolves all of LIPA’s claims related to Tropical Storm Isaias and the DPS investigation. Any amendments to the OSA will require the approval of the New York Attorney General and the New York Comptroller. The OSA contract term will continue through 2025, with a mutual option to extend. No assurances can be given regarding reaching final settlement agreement, obtaining New York approvals and the closing of the inquiry by the Attorney General.

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

Climate Strategy and Sustainability Efforts

For more than a century, our mission has been to provide safe access to an around-the-clock supply of reliable, affordable energy. Building on this mission, we are working toward a future where customers universally use less energy, the energy they use is cleaner, and its delivery is more reliable and more resilient. In June 2021, we accelerated and expanded our net zero vision by 20 years, establishing a net zero carbon emissions by 2030 goal that includes direct greenhouse gas (GHG) emissions (Scope 1) and indirect GHG emissions from operations (Scope 2) at both PSEG Power and PSE&G (covering our electric and natural gas utility operations), assuming advances in technology, public policy and customer behavior. Scope 1 emissions include power generation, methane leaks, vehicle fleet emissions, sulfur hexafluoride and refrigerant leaks. Scope 2 emissions include both gas and electric purchased energy for our PSE&G facilities and line losses. In September 2021, we also committed to the Race to Zero Campaign, an initiative supported by the United Nations and other leading organizations. Under the Race to Zero, we have committed to develop science-based emission reduction targets across Scopes 1, 2, and 3 (representing use of products by our customers and our own operations), in line with 1.5oC emissions scenarios and the criteria and recommendations of the Science Based Targets initiative.

PSE&G has undertaken a number of initiatives that support the reduction of GHG emissions and the implementation of energy efficiency initiatives. PSE&G is committed to delivering natural gas to almost two million customers throughout New Jersey and we are equally committed to reducing GHG emissions associated with such operations. The first phase of our GSMP replaced approximately 450 miles of cast-iron and unprotected steel gas 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. Through GSMP II, from 2018 through 2023 we expect an approximate 22% reduction in methane, and assuming a continuation of GSMP, we expect an approximate 60% reduction in methane emissions from 2011 through 2030. In addition, PSE&G’s recently approved CEF-EE, CEF-EC and CEF-EV programs and the proposed CEF-ES program are intended to support New Jersey’s EMP through

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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. We also continue to assess physical risks of climate change and adapt our capital investment program to improve the reliability and resiliency of our system in an environment of increasing frequency and severity of weather events, notably through our investments in Energy Strong.

We also continue to focus on providing cleaner energy for our customers. Our priority is to preserve the economic viability of our nuclear units, which provide over 90% of the carbon-free energy in New Jersey, by obtaining a long-term arrangement that recognizes the value of emission-free generation and reduces market risk. We also continue to explore investment opportunities in offshore wind, both generation and transmission to support the cost-efficient connection of offshore wind generation projects to the New Jersey electric system.

Offshore Wind

In December 2020, PSEG entered into a definitive agreement with Ørsted North America to acquire a 25% equity interest in Ørsted’s Ocean Wind project. Ocean Wind was selected by New Jersey to be the first offshore wind farm as part of the State’s intention to add 7,500 MW of offshore wind generating capacity by 2035. The Ocean Wind project is expected to achieve full commercial operation in 2025. On March 31, 2021, the BPU approved PSEG’s investment in Ocean Wind and the acquisition was completed in April 2021. Additionally, PSEG and Ørsted each owns 50% of Garden State Offshore Energy LLC (GSOE) which holds rights to an offshore wind lease area just south of New Jersey. PSEG and Ørsted are exploring opportunities to develop the GSOE lease area. In April 2021, PJM announced the opening of the first public policy Order 1000 bid window that would utilize the state agreement approach for transmission projects to support the full 7,500 MW of offshore wind generation that New Jersey plans to procure. The state agreement approach requires customers in the requesting state - in this case New Jersey - to pay for the costs of these public policy transmission projects. In September 2021, PSEG, under its newly-formed competitive transmission company, PSEG Renewables Transmission LLC, and Ørsted N.A, Transmission, LLC (Ørsted Transmission) jointly submitted several proposals in response to the solicitation, including multi-spur options and an offshore network proposal. If awarded, the projects would be developed through a 50/50 joint venture with Ørsted Transmission. The BPU has announced that it will select the winning proposals in the second half of 2022 with likely in-service dates by 2030.

Operational Excellence

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

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 the first nine months of 2021 as we

• maintained sufficient liquidity,

• maintained solid investment grade credit ratings, and

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

We expect to be able to fund our planned capital requirements, as described in Liquidity and Capital Resources without the issuance of new equity. Our planned capital requirements, which are driven by growth in our regulated utility, and the sale of our fossil generating fleet are expected to improve our financial flexibility. In conjunction with the sale of our Fossil business, in October 2021 we redeemed all of PSEG Power’s remaining debt. See Item 1. Note 12. Debt and Credit Facilities for additional details. We announced a $500 million share repurchase program subject to the closing of the Fossil sale.

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Financial Results

The results for PSEG, PSE&G and PSEG Power for the three months and nine months ended September 30, 2021 and 2020 are presented as follows:

						Three Months Ended												Nine Months Ended
						September 30,												September 30,
			Earnings (Losses)			2021						2020						2021						2020
						Millions
			PSE&G			$	389					$	313					$	1,175					$	1,036
			PSEG Power (A)			(1,933)						254						(2,255)						437
			Other (B)			(20)						8						(13)						1
			PSEG Net Income (Loss)			$	(1,564)					$	575					$	(1,093)					$	1,474
			PSEG Net Income (Loss) Per Share (Diluted)			$	(3.10)					$	1.14					$	(2.17)					$	2.91

(A)Includes an after-tax impairment loss and other charges of $1,563 million for the three months and $1,936 million for the nine months ended September 30, 2021 related to the pending sale of PSEG Power’s Fossil generation assets. Includes an after-tax gain of $86 million for the three and nine months ended September 30, 2020 on the sale of PSEG Power’s interest in the Yards Creek generation facility. See Item 1. Note 4. Early Plant Retirements/Asset Dispositions and Impairments for additional information.

(B)Other includes after-tax activities at the parent company, PSEG LI, and Energy Holdings as well as intercompany eliminations.

PSEG Power’s results above include the Nuclear Decommissioning Trust (NDT) Fund activity and the impacts of non-trading commodity mark-to-market (MTM) activity, which consist of the financial impact from positions with future delivery dates.

The variances in our Net Income attributable to changes related to the NDT Fund and MTM are shown in the following table:

						Three Months Ended												Nine Months Ended
						September 30,												September 30,
						2021						2020						2021						2020
						Millions, after tax
			NDT Fund Income (Expense) (A) (B)			$	(11)					$	60					$	68					$	43
			Non-Trading MTM Gains (Losses) (C)			$	(478)					$	(59)					$	(718)					$	(59)

(A)NDT Fund Income (Expense) includes gains and losses on NDT securities which are recorded in Net Gains (Losses) on Trust Investments. See Item 1. Note 9. 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 and Maintenance (O&M) Expense and the depreciation related to the ARO asset recorded in Depreciation and Amortization (D&A) Expense.

(B)Net of tax (expense) benefit of $5 million and $(40) million for the three months and $(48) million and $(30) million for the nine months ended September 30, 2021 and 2020, respectively.

(C)Net of tax (expense) benefit of $188 million and $23 million for the three months and $280 million and $23 million for the nine months ended September 30, 2021 and 2020, respectively.

Our $2,139 million and $2,567 million decreases in Net Income for the three months and nine months ended September 30, 2021, respectively, were driven primarily by

• an impairment loss on the pending sale of the Fossil generation assets at PSEG Power (see Item 1. Note 4. Early Plant Retirements/Asset Dispositions and Impairments for additional information),

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

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

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

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• higher pension and OPEB credits.

The decrease in Net Income for the three month period was also due to lower realized gains and higher unrealized losses on NDT Fund equity securities in 2021.

Disciplined Investment

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

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

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

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

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

• completed the sale of PSEG Power’s Solar Source units and are in the process of obtaining state and federal regulatory approvals to complete the sale of the fossil generation 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 Part I, Item 1. Business—Regulatory Issues in our Form 10-K and Item 5. Other Information in our Quarterly Reports on Form 10-Q for the periods ending March 31, 2021 and June 30, 2021 (first and second quarter 2021 10-Qs) and this Quarterly Report on Form 10-Q.

Transmission Rate Proceedings and ROE

In March 2019, FERC issued a Notice of Inquiry seeking comments on improvements to FERC’s electric transmission incentives policy. Subsequently, in April 2021, FERC issued a supplemental notice of proposed rulemaking to eliminate the incentive for Regional Transmission Organization (RTO) membership for transmitting utilities that have already received the incentive for three or more years. PSE&G began receiving a 50 basis point adder for RTO membership in 2008. Elimination of the adder for RTO membership could reduce PSE&G’s annual Net Income and annual cash inflows by approximately $30 million.

In October 2021, FERC approved a settlement agreement effective August 1, 2021 that we reached with the BPU and the New Jersey Rate Counsel about the level of PSE&G’s base transmission ROE and other formula rate matters. The settlement reduces PSE&G’s base ROE from 11.18% to 9.9%. As a result of this settlement, PSE&G projects Net Income will decrease by approximately $50 million to $60 million during the first twelve months following the August 1, 2021 implementation date. The agreement provides that the settling parties will not seek changes to our transmission formula rate for three years. We will be implementing the effects of the agreement over the next several months.

Wholesale Power Market Design

In July 2021, PJM submitted to FERC a proposal to replace the current MOPR, which applies to both new and existing resources that receive certain out-of-market payments, with new provisions that accommodate state public policy programs that do not attempt to set the price of capacity. Under the PJM proposal, PSEG Power’s New Jersey nuclear plants that receive ZEC payments would not be subject to the MOPR. In September 2021, FERC issued a notice that it was not able to act on PJM’s proposed changes to the MOPR because of a split among the Commissioners on the lawfulness of PJM’s proposal. Therefore, PJM’s rules became automatically effective as of September 29, 2021 and will apply to the next base residual auction, which has been delayed until January 25, 2022 in order to allow entities additional time to meet the pre-auction deadlines.

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

In July 2021, the BPU issued a report on its investigation related to whether New Jersey can achieve its long-term clean energy and environmental objectives under the current resource adequacy procurement paradigm. The report found that participating in

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

In January 2020, New Jersey rejoined the Regional Greenhouse Gas Initiative (RGGI). As a result, generating plants operating in New Jersey, including those owned by PSEG Power, that emit carbon dioxide emissions will be required to procure credits for each ton they emit. 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 and penalties 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. In addition, PSEG Power will retain ownership of certain assets and liabilities excluded from the sale of its fossil generation business, primarily related to obligations under certain environmental regulations, including possible remediation obligations under the New Jersey Industrial Site Recovery Act and the Connecticut Transfer Act. The amounts for any such environmental remediation are not estimable, but may be material. We are also currently involved in a number of proceedings relating to sites where other hazardous substances may have been discharged and may be subject to additional proceedings in the future, and the costs and penalties of any such remediation efforts could be material.

For further information regarding the matters described above, as well as other matters that may impact our financial condition and results of operations, see Item 1. Note 11. Commitments and Contingent Liabilities.

Nuclear

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

In April 2021, PSEG Power’s Salem 1, Salem 2 and Hope Creek nuclear plants were awarded ZECs for the three-year eligibility period starting June 2022 at the same approximate $10 per MWh received during the current ZEC period through May 2022 referenced above. As a result, each nuclear plant is expected to receive ZEC revenue for an additional three years starting June 2022. The terms and conditions of this April 2021 ZEC award are the same as the current ZEC period as discussed above. While the ZEC program has preserved these units to date, PSEG will simultaneously seek long-term legislative or other solutions for our New Jersey nuclear plants that sufficiently values them for their carbon-free, fuel diversity and resilience attributes. No assurances can be given regarding future ZEC awards or other long-term solutions.

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

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

In the event that (i) the ZEC program is overturned or is otherwise materially adversely modified through legal process; or (ii) any of the Salem 1, Salem 2 and Hope Creek plants is not sufficiently valued for its environmental, fuel diversity or resilience attributes in future periods and does not otherwise experience a material financial change that would remove the need for such attributes to be sufficiently valued, PSEG Power will take all necessary steps to cease to operate all of these plants. Alternatively, even with sufficient valuation of these attributes, if the financial condition of the plants is materially adversely impacted by changes in commodity prices, FERC’s changes to the capacity market construct (absent sufficient capacity

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revenues provided under a program approved by the BPU in accordance with a FERC-authorized capacity mechanism), or, in the case of the Salem nuclear plants, decisions by the EPA and state environmental regulators regarding the implementation of Section 316(b) of the Clean Water Act and related state regulations, or other factors, PSEG Power will take all necessary steps to cease to operate all of these plants. Ceasing operations of these plants would result in a material adverse impact on PSEG’s and PSEG Power’s results of operations.

Tax Legislation

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

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

In July 2020, the Internal Revenue Service (IRS) issued final and proposed regulations addressing the limitation on deductible business interest expense contained in the Tax Cuts and Jobs Act. These regulations retroactively allow depreciation to be added back in computing the 30% adjusted taxable income (ATI) cap, increasing the amount of interest that can be deducted by unregulated businesses in years before 2022. For 2022 and after, the regulations continue to disallow the addback of depreciation in the computation of ATI, effectively lowering the cap on the amount of deductible business interest. The portion of PSEG’s and PSEG Power’s business interest expense that was disallowed in 2018 and 2019 will now be deductible in those respective years.

In March 2020, the federal Coronavirus Aid, Relief, and Economic Security Act (CARES Act) was enacted. The CARES Act allows a five-year carryback of any net operating loss (NOL) generated in a taxable year beginning after December 31, 2017 and before January 1, 2021. The CARES Act allowed us to carry back the 2018 tax NOL generated by the final Section 163(j) regulations, which will provide a future tax benefit, subject to approval by the IRS and the Joint Committee on Taxation.

Future Outlook

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

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

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

• deliver on our Human Capital Management strategy to attract, develop and retain a diverse, high-performing workforce,

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

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

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

• successfully close the transactions involving PSEG Power’s fossil generating assets as we shift our business mix and continue to transition to a predominantly regulated utility and contracted generating company with a carbon-free nuclear and regional offshore wind fleet,

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

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

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

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

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

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

• future changes in federal and state tax laws, including The American Jobs Plan, Made in America Tax Plan, or any other associated tax legislation, and

• the impact of changes in demand, natural gas and electricity prices, and expanded efforts to decarbonize several sectors of the economy.

We continually assess a broad range of strategic options to maximize long-term stockholder value and address the interests of our multiple stakeholders. In assessing our options, we consider a wide variety of factors, including the performance and prospects of our businesses; the views of investors, regulators, rating agencies, customers and employees; our existing indebtedness and restrictions it imposes; and tax considerations, among other things. Strategic options available to us include:

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

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

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

• acquisitions, dispositions and other transactions involving our common stock, assets or businesses that could provide value to customers and shareholders.

There can be no assurance, however, that we will successfully develop and execute any of the strategic options noted above, or any additional options we may consider in the future. The execution of any such strategic plan may not have the expected benefits or may have unexpected adverse consequences.

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RESULTS OF OPERATIONS

PSEG

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 1. Note 20. Related-Party Transactions.

						Three Months Ended												Increase/ (Decrease)												Nine Months Ended												Increase/ (Decrease)
						September 30,															September 30,
						2021						2020						2021 vs. 2020												2021						2020						2021 vs. 2020
						Millions												Millions						%						Millions												Millions						%
			Operating Revenues			$	1,903					$	2,370					$	(467)					(20)						$	6,666					$	7,201					$	(535)					(7)
			Energy Costs			860						775						85						11						2,495						2,276						219						10
			Operation and Maintenance			807						767						40						5						2,368						2,254						114						5
			Depreciation and Amortization			283						317						(34)						(11)						946						956						(10)						(1)
			(Gains) Losses on Asset Dispositions and Impairments			2,158						(122)						2,280						N/A						2,615						(122)						2,737						N/A
			Income from Equity Method Investments			3						4						(1)						(25)						12						10						2						20
			Net Gains (Losses) on Trust Investments			(17)						107						(124)						N/A						124						87						37						43
			Other Income (Deductions)			35						39						(4)						(10)						93						81						12						15
			Net Non-Operating Pension and OPEB Credits (Costs)			82						62						20						32						246						186						60						32
			Interest Expense			144						149						(5)						(3)						437						453						(16)						(4)
			Income Tax (Benefit) Expense			(682)						121						(803)						N/A						(627)						274						(901)						N/A

The following discussions for PSE&G and PSEG Power provide a detailed explanation of their respective variances.

PSE&G

						Three Months Ended												Increase/ (Decrease)												Nine Months Ended												Increase/ (Decrease)
						September 30,															September 30,
						2021						2020						2021 vs. 2020												2021						2020						2021 vs. 2020
						Millions												Millions						%						Millions												Millions						%
			Operating Revenues			$	1,820					$	1,660					$	160					10						$	5,407					$	4,999					$	408					8
			Energy Costs			698						663						35						5						2,056						1,881						175						9
			Operation and Maintenance			422						409						13						3						1,239						1,175						64						5
			Depreciation and Amortization			226						218						8						4						698						657						41						6
			Gain on Asset Dispositions			4						—						4						N/A						4						—						4						N/A
			Net Gains (Losses) on Trust Investments			—						1						(1)						N/A						1						2						(1)						(50)
			Other Income (Deductions)			20						28						(8)						(29)						72						81						(9)						(11)
			Net Non-Operating Pension and OPEB Credits (Costs)			67						51						16						31						199						154						45						29
			Interest Expense			102						97						5						5						301						291						10						3
			Income Tax Expense (Benefit)			74						40						34						85						214						196						18						9

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Three Months Ended September 30, 2021 as Compared to 2020

Operating Revenues increased $160 million due to changes in delivery, commodity, clause and other operating revenues.

Delivery Revenues increased $109 million due primarily to

• Transmission revenues were $64 million higher due primarily to an increase in revenue requirements attributable to higher rate base investment, partially offset by the estimated impact of the ROE settlement. See Item 1. Note 6. Rate Filings.

• Gas distribution revenues increased $32 million due primarily to a reduction of $27 million in WNC revenue accruals in 2020, a $4 million increase in GSMP II revenues and a $1 million increase in Green Program Recovery Charge (GPRC) revenues in 2021.

• Electric distribution revenues increased $13 million due primarily to an increase of $20 million from CIP decoupling and a $5 million increase in GPRC collections, partially offset by a $12 million decrease attributable to lower sales volumes.

Commodity Revenues increased $30 million as a result of higher Electric revenues and higher Gas revenues. The changes in Commodity revenues for both electric and gas are entirely offset by the changes in Energy Costs. PSE&G earns no margin on the provision of BGS to retail customers and basic gas supply service (BGSS).

• Electric commodity revenues increased $21 million due primarily to a $12 million increase in sales volumes and $9 million in higher BGS prices.

• Gas commodity revenues increased $9 million due primarily to higher BGSS prices of $11 million, partially offset by lower BGSS sales volumes of $2 million.

Clause Revenues increased $7 million due primarily to a $16 million increase in the Tax Adjustment Credit (TAC) deferral, partially offset by an $8 million decrease in GPRC deferrals. The changes in TAC and GPRC deferral amounts are entirely offset by changes in the amortization of Regulatory Assets and Regulatory Liabilities and related costs in O&M, D&A, Interest and Income Tax Expenses. PSE&G does not earn margin on TAC and GPRC deferrals.

Other Operating Revenues increased $14 million due primarily to a $4 million increase in appliance service revenues and a $7 million increase in Transition Renewable Energy Certificate (TREC) revenues. These increases were partially offset by a $1 million decrease in ZEC revenues and a $1 million decrease in Solar Renewable Energy Certificate (SREC) revenues. The changes in TREC, ZEC and SREC components of revenues are entirely offset by changes in Energy Costs.

Operating Expenses

Energy Costs increased $35 million. This is entirely offset by changes in Commodity Revenues and Other Operating Revenues.

Operation and Maintenance increased $13 million due primarily to a $23 million increase driven by timing of the 2020 COVID-19 deferral, the cumulative effect of which was recorded in September 2020, a $5 million increase in transmission expenditures, a $4 million increase in distribution operations maintenance and a $3 million increase in clause and renewable-related expenses, partially offset by a $9 million decrease in gas operations expenditures, a $7 million decrease in appliance service costs and a $6 million decrease in other operating expenses.

Depreciation and Amortization increased $8 million due primarily to a $16 million increase for additional plant placed in service, partially offset by a decrease of $8 million due to new transmission depreciation rates that became effective in August 2021.

Other Income (Deductions) decreased $8 million primarily due to a decrease in the Allowance for Funds Used During Construction (AFUDC).

Net Non-Operating Pension and OPEB Credits (Costs) increased $16 million due primarily to a $12 million decrease in interest cost and a $7 million increase in the expected return on plan assets, partially offset by a $2 million increase in the amortization of the net actuarial loss and a $1 million decrease in the amortization of net prior service credit.

Interest Expense increased $5 million due primarily to a $3 million reduction in AFUDC and a $1 million increase from net debt issuances in 2021.

Income Tax Expense increased $34 million due primarily to higher pre-tax income.

Nine Months Ended September 30, 2021 as Compared to 2020

Operating Revenues increased $408 million due to changes in delivery, commodity, clause and other operating revenues.

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Delivery Revenues increased $191 million due primarily to

• Transmission revenues were $121 million higher due primarily to an increase in revenue requirements attributable to higher rate base investment, partially offset by the estimated impact of the ROE settlement. See Item 1. Note 6. Rate Filings.

• Gas distribution revenues increased $51 million due primarily to a $28 million increase in GSMP II collections, a $26 million increase due to higher sales volumes and a $6 million increase in GPRC revenues. These increases were partially offset by a $9 million decrease in WNC revenue accruals in 2020.

• Electric distribution revenues increased $46 million due primarily to $21 million from CIP decoupling, $15 million in higher sales volumes and a $10 million increase in GPRC collections.

• Electric and Gas revenues decreased $27 million due to a net increase in the flowback to customers of excess deferred tax liabilities and tax repair-related accumulated deferred income tax benefits resulting from rate reductions, which is offset in Income Tax Expense.

Commodity Revenues increased $176 million as a result of higher Gas revenues and higher Electric revenues. The changes in Commodity revenues for both gas and electric are entirely offset by the changes in Energy Costs. PSE&G earns no margin on the provision of BGSS and BGS to retail customers.

• Gas commodity revenues increased $101 million due primarily to higher BGSS prices of $60 million and higher BGSS sales volumes of $41 million.

• Electric commodity revenues increased $75 million due primarily to a $109 million increase in sales volumes, partially offset by $34 million in lower BGS prices.

Clause Revenues increased $23 million due primarily to higher SBC revenues of $19 million, an $18 million increase in TAC deferrals and a $3 million increase in Margin Adjustment Clause (MAC) credits. These increases were partially offset by a $16 million decrease in GPRC deferrals. The changes in SBC revenues and MAC credits and TAC and GPRC deferral amounts are entirely offset by changes in the amortization of Regulatory Assets and Regulatory Liabilities and related costs in O&M, D&A, Interest and Income Tax Expenses. PSE&G does not earn margin on SBC revenues, MAC credits or TAC and GPRC deferrals.

Other Operating Revenues increased $18 million due primarily to a $16 million increase in appliance service revenues and a $20 million increase in TREC revenues. These increases were partially offset by a $20 million decrease in SREC revenues and a $1 million decrease in ZEC revenues. The changes in TREC, SREC and ZEC components of revenues are entirely offset by changes to Energy Costs.

Operating Expenses

Energy Costs increased $175 million. This is entirely offset by changes in Commodity Revenues and Other Operating Revenues.

Operation and Maintenance increased $64 million due primarily to a $31 million increase in clause and renewable-related expenses, a $22 million increase in transmission expenditures, an $8 million increase in appliance service costs, a $6 million increase in corrective maintenance, and a $10 million increase in other operating expenses. These increases were partially offset by a $13 million decrease in gas operations expenditures.

Depreciation and Amortization increased $41 million due primarily to a $41 million increase related to additional plant in service, a $4 million increase in the amortization of Regulatory Assets and a $3 million increase in software amortization. These increases were partially offset by an $8 million decrease due to new transmission depreciation rates that became effective in August 2021.

Other Income (Deductions) decreased $9 million primarily due to a $7 million decrease in AFUDC and a $2 million decrease in solar loan interest.

Net Non-Operating Pension and OPEB Credits (Costs) increased $45 million due primarily to a $34 million decrease in interest cost and a $20 million increase in the expected return on plan assets, partially offset by a $5 million increase in the amortization of the net actuarial loss and a $4 million decrease in the amortization of net prior service credit.

Interest Expense increased $10 million due primarily to a $4 million increase from net debt issuances in 2021, a $3 million increase from net debt issuances in 2020 and a $3 million reduction in AFUDC in 2021.

Income Tax Expense increased $18 million due primarily to higher pre-tax income, partially offset by an increase in the tax benefits from the 2021 flowback of PSE&G’s excess deferred income tax liabilities and CEF program investments.

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PSEG Power

						Three Months Ended												Increase/ (Decrease)												Nine Months Ended												Increase/ (Decrease)
						September 30,															September 30,
						2021						2020						2021 vs. 2020												2021						2020						2021 vs. 2020
						Millions												Millions						%						Millions												Millions						%
			Operating Revenues			$	51					$	746					$	(695)					(93)						$	1,598					$	2,649					$	(1,051)					(40)
			Energy Costs			290						290						—						—						1,243						1,289						(46)						(4)
			Operation and Maintenance			230						213						17						8						711						679						32						5
			Depreciation and Amortization			50						91						(41)						(45)						225						276						(51)						(18)
			(Gains) Losses on Asset Dispositions and Impairments			2,162						(122)						2,284						N/A						2,619						(122)						2,741						N/A
			Income from Equity Method Investments			3						4						(1)						(25)						12						10						2						20
			Net Gains (Losses) on Trust Investments			(17)						103						(120)						N/A						120						79						41						52
			Other Income (Deductions)			16						11						5						45						20						—						20						N/A
			Net Non-Operating Pension and OPEB Credits (Costs)			12						8						4						50						35						25						10						40
			Interest Expense			19						28						(9)						(32)						70						92						(22)						(24)
			Income Tax Expense (Benefit)			(753)						118						(871)						N/A						(828)						112						(940)						N/A

Three Months Ended September 30, 2021 as Compared to 2020

Operating Revenues decreased $695 million due primarily to changes in generation and gas supply revenues.

Generation Revenues decreased $705 million due primarily to

• a net decrease of $565 million due to higher net MTM losses in 2021 as compared to 2020. Of this amount, there was a $736 million decrease due to changes in forward prices this year as compared to last year, partially offset by a $171 million increase due to gains on positions reclassified to realized upon settlement in 2021 as compared to losses in 2020,

• a net decrease of $117 million due primarily to $99 million in lower volumes of electricity sold under the BGS contracts, coupled with an $18 million impact from the transfer of responsibility for firm transmission services from BGS suppliers to the Electric Distribution Companies (EDCs),

• a net decrease of $29 million due primarily to lower prices in the PJM region coupled with lower net volumes sold in the New England (NE) region, partially offset by higher net volumes sold in PJM and higher prices in the New York (NY) region, and

• a net decrease of $17 million in solar revenues due to the sale of the solar plants in June 2021,

• partially offset by a net increase of $22 million in capacity revenues due primarily to lower load obligations in the PJM and NE regions, partially offset by the retirement of Bridgeport Harbor 3 (BH3) in the NE region.

Gas Supply Revenues increased $11 million due primarily to

• a net increase of $32 million related to sales to third parties, of which $34 million was due to higher average sales prices, partially offset by a decrease of $2 million due to lower volumes sold, and

• a net increase of $4 million in sales under the BGSS contract primarily due to higher prices of $6 million, partially offset by lower sales volumes of $2 million,

• partially offset by a decrease of $25 million due to higher MTM losses in 2021 as compared to 2020 driven by changes in forward prices.

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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 was flat due to

Generation costs decreased $46 million due primarily to

• a net decrease of $34 million in transmission costs due to an $18 million impact from the transfer of responsibility for firm transmission services under BGS contracts from BGS suppliers to the EDCs, coupled with a $16 million decrease from changes in BGS and other load,

• a net decrease of $20 million due primarily to a decrease in costs for Renewable Energy Credits related to load contracts in the PJM and NE regions, and

• a net decrease of $7 million due to higher net MTM gains in 2021 as compared to 2020. Of this amount, there was a $63 million decrease due to changes in forward prices this year as compared to last year, partially offset by a $56 million increase due to losses on positions reclassified to realized upon settlement in 2021 as compared to gains in 2020,

• partially offset by a net increase of $22 million in fuel costs due to higher gas prices in the NE and NY regions.

Gas costs increased $46 million due mainly to

• a net increase of $31 million related to sales to third parties, of which $33 million was due to an increase in the average cost of gas, partially offset by a decrease of $2 million due to lower volumes sold, and

• a net increase of $16 million related to sales under the BGSS contract, primarily due to higher prices. Included in the 2020 average cost of gas were $11 million of interstate gas pipeline refunds due to a settlement on pipeline rates from prior periods.

Operation and Maintenance increased $17 million due primarily to increased property tax and service agreement payments at our fossil plants coupled with higher planned outage costs in 2021 at our Salem nuclear plant, higher operating costs at both the Salem and Hope Creek nuclear plants and severance costs related to the sale of Fossil’s generating portfolio.

Depreciation and Amortization decreased $41 million due primarily to ceasing recording depreciation expense in August 2021 on Fossil’s generating portfolio, the sale of Solar Source in June 2021 and the retirement of the BH3 unit effective May 31, 2021.

(Gains) Losses on Asset Dispositions and Impairments reflects a $2,162 million impairment loss of Fossil’s generating portfolio in 2021 and a $122 million gain on the sale of our ownership interest in the Yards Creek generation facility in 2020.

Net Gains (Losses) on Trust Investments decreased $120 million due primarily to a $67 million decrease due to $33 million of net unrealized losses in 2021 as compared to $34 million of net unrealized gains on NDT Fund equity securities and a $53 million decrease in net realized gains on NDT Fund investments.

Other Income (Deductions) increased $5 million primarily due to higher interest and dividend income on NDT Fund investments in 2021.

Interest Expense decreased $9 million due primarily to $994 million of debt maturities in 2021 and $96 million in PSEG Power Senior Notes that were redeemed as part of the debt exchange with PSEG in 2020.

Income Tax Expense decreased $871 million due primarily to lower pre-tax income.

Nine Months Ended September 30, 2021 as Compared to 2020

Operating Revenues decreased $1,051 million due primarily to changes in generation and gas supply revenues.

Generation Revenues decreased $1,123 million due primarily to

• a net decrease of $985 million due to higher MTM losses in 2021 as compared to 2020. Of this amount, there was a $991 million decrease due to changes in forward prices this year as compared to last year, partially offset by a $6 million increase due to less losses on positions reclassified to realized upon settlement in 2021 as compared to 2020,

• a net decrease of $201 million due primarily to $132 million of lower volumes of electricity sold under the BGS contracts, coupled with a $69 million impact from the transfer of responsibility for firm transmission services from BGS suppliers to the EDCs, and

• a net decrease of $18 million in solar revenues due to the sale of the solar plants in June 2021,

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• partially offset by a net increase of $43 million due primarily to higher average realized prices and higher volumes sold in the NE and NY regions. This was partially offset by lower realized prices in the PJM region, and

• a net increase of $39 million in capacity revenues due primarily to increases in auction prices in the PJM region, partially offset by lower capacity prices and the retirement of BH3 in the NE region.

Gas Supply Revenues increased $73 million due primarily to

• a net increase of $54 million in sales under the BGSS contract primarily due to higher sales volumes of $48 million and higher prices of $6 million, and

• a net increase of $52 million related to sales to third parties, of which $68 million was due to higher average sales prices, partially offset by $16 million due to lower volumes sold,

• partially offset by a decrease of $33 million due to higher MTM losses in 2021 as compared to 2020 driven by changes in forward prices.

Operating Expenses

Energy Costs represent the cost of generation, which includes fuel costs for generation as well as purchased energy in the market, and gas purchases to meet PSEG Power’s obligation under its BGSS contract with PSE&G. Energy Costs decreased $46 million due to

Generation costs decreased $135 million due primarily to

• a net decrease of $103 million due to higher net MTM gains in 2021 as compared to 2020. Of this amount, there was an $87 million decrease due to changes in forward prices this year as compared to last year coupled with a $16 million decrease due to more gains on positions reclassified to realized upon settlement in 2021 as compared to 2020,

• a net decrease of $101 million in transmission costs primarily due to a $69 million impact from the transfer of responsibility for firm transmission services under BGS contracts from BGS suppliers to the EDCs, coupled with a $32 million decrease from changes in BGS and other load, and

• a decrease of $11 million due to a lower-of-cost-or-market adjustment on oil inventory caused by a decrease in oil demand and pricing in 2020,

• partially offset by a net increase of $90 million in fuel costs reflecting higher gas prices in the PJM, NY, and NE regions coupled with the utilization of higher volumes of coal in the NE region.

Gas costs increased $89 million due mainly to

• a net increase of $46 million related to sales to third parties, of which $61 million was due to an increase in the average cost of gas, partially offset by a decrease of $15 million due to lower volumes sold, and

• a net increase of $43 million in costs related to sales under the BGSS contract, of which $41 million was due to higher send out volumes and $2 million due to an increase in the average cost of gas. Included in the 2020 average cost of gas were $18 million of interstate gas pipeline refunds due to a settlement on pipeline rates from prior periods.

Operation and Maintenance increased $32 million due primarily to a refueling outage in 2021 at our 100%-owned Hope Creek nuclear plant as compared to an outage in 2020 at our 57%-owned Salem 2 nuclear plant and severance costs related to the sale of Fossil’s generating portfolio, partially offset by lower costs in 2021 due to the sale of our ownership interest in the Yards Creek generation facility in September 2020.

Depreciation and Amortization decreased $51 million due primarily to ceasing depreciation expense on Fossil’s generating plants, the sale of Solar Source and the retirement of BH3 in 2021.

(Gains) Losses on Asset Dispositions and Impairments reflects $2,681 million of impairment losses of Fossil’s generating plants, partially offset by a $62 million gain from the sale of Solar Source in 2021 and a $122 million gain on the sale of our ownership interest in the Yards Creek generation facility in September 2020.

Net Gains (Losses) on Trust Investments increased $41 million due primarily to a $55 million increase in net realized gains on NDT Fund investments, partially offset by a $15 million increase in net unrealized losses on equity investments in the NDT Fund.

Other Income (Deductions) increased $20 million due primarily to less purchases of NOL tax benefits under the New Jersey Technology Tax Benefit Transfer Program and higher interest and dividend income on NDT Fund investments in 2021.

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Non-Operating Pension and OPEB Credits (Costs) increased $10 million due to an $11 million decrease in interest cost and a $4 million increase in the expected return on plan assets, partially offset by $2 million in co-owner charges and a $2 million decrease in the amortization of net prior service credit.

Interest Expense decreased $22 million due primarily to lower interest expense due to $994 million of debt maturities in 2021 and $406 million of debt maturities in 2020, and $96 million in PSEG Power Senior Notes that were redeemed as part of the debt exchange with PSEG in 2020.

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

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.

Operating Cash Flows

We continue to expect our operating cash flows combined with cash on hand and financing activities to be sufficient to fund planned capital expenditures and shareholder dividends.

For the nine months ended September 30, 2021, our operating cash flow decreased $1,339 million as compared to the same period in 2020. The net decrease was primarily due to the net changes from our subsidiaries, as discussed below, and lower tax refunds at the parent company, partially offset by tax refunds in 2021 as compared to tax payments in 2020 at Energy Holdings.

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

PSE&G

PSE&G’s operating cash flow decreased $141 million from $1,424 million to $1,283 million for the nine months ended September 30, 2021, as compared to the same period in 2020, due primarily to increases in electric energy and vendor payments, a net increase in regulatory deferrals, and higher tax payments in 2021, partially offset by higher earnings.

PSEG Power

PSEG Power’s operating cash flow decreased $1,166 million from $1,000 million to $166 million for the nine months ended September 30, 2021, as compared to the same period in 2020, due to lower earnings and a $933 million reduction related to net cash collateral posting requirements and higher tax payments in 2021.

Short-Term Liquidity

PSEG meets its short-term liquidity requirements, as well as those of PSEG Power, primarily through the issuance of commercial paper and, from time to time, short-term loans. PSE&G maintains its own separate commercial paper program to meet its short-term liquidity requirements. Each commercial paper program is fully back-stopped by its own separate credit facilities.

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

As part of the generation business, we hedge generation output to mitigate market price volatility. When prices increase, hedged positions could be out-of-the-money, requiring margin postings. In times of significantly rising market prices, those collateral postings could be substantial. During the third quarter of 2021, PSEG Power experienced a substantial increase in net cash collateral postings related to hedge positions that are out-of-the-money due to an increase in energy market prices, from $343 million at the end of June to $999 million at the end of September. PSEG issued short-term borrowings, including commercial paper, and provided short-term loans to PSEG Power in order to satisfy the increase in collateral postings and to prepare for the PSEG Power debt redemption. Subsequent to the end of September, collateral postings continued to increase and as a result, in October, PSEG Power borrowed $755 million from its credit facility to support its Senior Notes redemption and additional collateral postings, as needed. As of the end of October, PSEG Power’s collateral postings were approximately $1.3 billion.

In March 2020, PSEG entered into a $300 million, 364-day term loan agreement which was prepaid in January 2021. In May and March 2021, PSEG entered into two 364-day variable rate term loan agreements for $750 million and $500 million,

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respectively. In August 2021, PSEG entered into a $1.25 billion, 364-day variable rate term loan agreement. These term loans are not included in the credit facility amounts presented in the following table.

Our total credit facilities and available liquidity as of September 30, 2021 were as follows:

			Company/Facility						As of September 30, 2021
			Total Facility						Usage						Available Liquidity
									Millions
			PSEG						$	1,500					$	1,207					$	293
			PSE&G						600						18						582
			PSEG Power						2,000						123						1,877
			Total						$	4,100					$	1,348					$	2,752

As of September 30, 2021, our credit facility capacity was in excess of our projected maximum liquidity requirements over our 12 month planning horizon, including access to external financing to meet redemptions. Our maximum liquidity requirements are based on stress scenarios that incorporate changes in commodity prices and the potential impact of PSEG Power losing its investment grade credit rating from S&P or Moody’s, which would represent a two level downgrade from its current Moody’s and S&P ratings. In the event of a deterioration of PSEG Power’s credit rating, certain of PSEG Power’s agreements allow the counterparty to demand further performance assurance. The potential additional collateral that we would be required to post under these agreements if PSEG Power were to lose its investment grade credit rating was approximately $887 million and $840 million as of September 30, 2021 and December 31, 2020, respectively.

For additional information, see Item 1. Note 12. Debt and Credit Facilities.

Long-Term Debt Financing

During the third quarter of 2021,

• PSEG Power redeemed its $44 million of Pennsylvania Economic Development Financing Authority Variable Rate Bonds, and

• PSE&G issued $425 million of 1.90% Secured Medium-Term Notes, Series N, due August 2031.

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

During the next twelve months,

• PSEG has $300 million of 2.00% Senior Notes maturing in November 2021.

PSEG, PSEG Power, Energy Holdings, PSEG LI and Services participate in a corporate money pool, an aggregation of daily cash balances designed to efficiently manage their respective short-term liquidity needs, which are accounted for as intercompany loans. Servco does not participate in the corporate money pool. Servco’s short-term liquidity needs are met through an account funded and owned by LIPA.

For additional information see Item 1. Note 12. Debt and Credit Facilities.

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. In the event of a prolonged economic downturn, 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. To the extent of a prolonged economic downturn, our funding requirements may increase in future periods to meet NRC minimum funding requirements.

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Common Stock Dividends

On July 20, 2021, our Board of Directors declared a $0.51 dividend per share of common stock for the third quarter of 2021. This reflects an indicative annual dividend rate of $2.04 per share. On September 27, 2021, PSEG announced its indicative annual dividend rate of $2.16 for 2022. 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 1. Note 18. Earnings Per Share (EPS) and Dividends.

Credit Ratings

If the rating agencies lower or withdraw our credit ratings, such revisions may adversely affect the market price of our securities and serve to materially increase our cost of capital and limit access to capital. Credit Ratings shown are for securities that we typically issue. Outlooks are shown for the credit ratings at each entity and can be Stable, Negative, or Positive. In May 2021, Moody’s changed PSE&G’s outlook to Negative from Stable. In August 2021, Moody’s changed PSEG and PSEG Power’s outlook to Negative from Stable. In October 2021, Moody’s downgraded PSEG’s senior unsecured notes rating to Baa2 from Baa1, PSE&G’s mortgage bond rating to A1 from Aa3 and commercial paper rating to P2 from P1, and assigned PSEG Power an Issuer Credit Rating of Baa2. Moody’s outlooks of PSEG, PSE&G and PSEG Power were changed to Stable from Negative. With the redemption of PSEG Power’s Senior Notes, S&P maintains an Issuer Credit Rating of BBB. There is no assurance that the ratings will continue for any given period of time or that they will not be revised by the rating agencies, if in their respective judgments, circumstances warrant. Each rating given by an agency should be evaluated independently of the other agencies’ ratings. The ratings should not be construed as an indication to buy, hold or sell any security.

									Moody’s (A)						S&P (B)
			PSEG
			Outlook						Stable						Stable
			Senior Notes						Baa2						BBB
			Commercial Paper						P2						A2
			PSE&G
			Outlook						Stable						Stable
			Mortgage Bonds						A1						A
			Commercial Paper						P2						A2
			PSEG Power
			Outlook						Stable						Stable
			Issuer Rating						Baa2						BBB

(A)Moody’s ratings range from Aaa (highest) to C (lowest) for long-term securities and P1 (highest) to NP (lowest) for short-term securities.

(B)S&P ratings range from AAA (highest) to D (lowest) for long-term securities and A1 (highest) to D (lowest) for short-term securities.

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. There were no material changes to our projected capital expenditures as compared to amounts disclosed in our 2020 Form 10-K.

PSE&G

During the nine months ended September 30, 2021, PSE&G made capital expenditures of $1,818 million, primarily for T&D system reliability. This does not include expenditures for cost of removal, net of salvage, of $88 million, which are included in operating cash flows.

PSEG Power

During the nine months ended September 30, 2021, PSEG Power made capital expenditures of $78 million, excluding $144 million for nuclear fuel, primarily related to various nuclear and fossil projects.

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ACCOUNTING MATTERS

For information related to recent accounting matters, see Item 1. Note 2. Recent Accounting Standards.