Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (MD&A)

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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) and Public Service Electric and Gas Company (PSE&G). Information contained herein relating to any individual company is filed by such company on its own behalf.

PSEG’s business consists of two reportable segments, PSE&G and PSEG Power LLC (PSEG Power), our principal direct wholly owned subsidiaries, which are:

PSE&G**—which is a public utility engaged principally in the transmission of electricity and distribution of electricity and natural gas in certain areas of New Jersey. PSE&G is subject to regulation by the New Jersey Board of Public Utilities (BPU) and the Federal Energy Regulatory Commission (FERC). PSE&G also invests in regulated solar generation projects and energy efficiency and related programs in New Jersey, which are regulated by the BPU, and
PSEG Power**—which is an energy supply company that integrates the operations of its merchant nuclear generating assets with its fuel supply functions through competitive energy sales via 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 and the states in which they operate.

PSEG’s other direct wholly owned subsidiaries are: PSEG Energy Holdings L.L.C. (Energy Holdings), which holds our investments in offshore wind ventures and legacy lease investments; PSEG Long Island LLC (PSEG LI), which operates the Long Island Power Authority’s (LIPA) transmission and distribution (T&D) system under an Operations Services Agreement (OSA); and PSEG Services Corporation (Services), which provides certain management, administrative and general services to PSEG and its subsidiaries at cost.

Our business discussion in Part I, Item 1. Business of our 2021 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 2021 and Future Outlook provided in Item 7 in our Form 10-K by describing significant events and business developments that have occurred during 2022 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 2022 AND FUTURE OUTLOOK

We are a public utility holding company that, acting through our wholly owned subsidiaries, is a predominantly regulated electric and gas utility and a carbon-free generation and infrastructure company. We are focused on meeting customer expectations and being well aligned with public policy objectives by investing to modernize our energy infrastructure, improve reliability, increase energy efficiency and deliver cleaner energy. Our business plan focuses on achieving growth by allocating capital primarily toward regulated investments in an effort to improve the sustainability and predictability of our business and reduce the impact of fluctuating commodity prices. In furtherance of these goals, over the past few years, our investments have altered our business mix to reflect a higher percentage of earnings contribution by PSE&G, which improves the sustainability and predictability of our earnings and cash flows. In February 2022, we completed the sale of PSEG Power’s 6,750 MW of fossil generation located in New Jersey, Connecticut, New York and Maryland, which represented an important milestone in our strategy and has further altered our business mix, resulting in an even higher percentage of earnings contribution by PSE&G going forward and provides more financial flexibility.

The ongoing coronavirus (COVID-19) pandemic and associated government actions and economic effects continue to impact our businesses as discussed further below.

PSE&G

At PSE&G, our focus is on enhancing reliability and resiliency of our T&D system, meeting customer expectations and supporting public policy objectives by investing capital in T&D infrastructure and clean energy programs. For the years 2021-2025, PSE&G’s capital investment program is estimated to be in a range of $14 billion to $16 billion, resulting in an expected compound annual growth in rate base of 6% to 7.5% from year-end 2021 to year-end 2025. The low end of this range includes an Infrastructure Advancement Program (IAP) which the BPU approved in June 2022 and 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

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approved timeframe of 2023. The IAP is a $511 million investment program made over four years to improve the reliability of the “last mile” of our electric distribution system and address aging substations and gas metering and regulating stations, with $351 million of the investment being recovered through periodic rate updates and the remaining $160 million recovered through future base rate cases. The upper end of our capital investment range 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 investments for GSMP and CEF-EE beyond current levels. We filed for a $320 million short-term extension of our CEF-EE program in September 2022, which we expect will be resolved in 2023. We also expect to file for an extension of our GSMP in the first quarter of 2023 and expect resolution which would provide for continuation of the program in 2024. A remaining component of our CEF-EV program related to medium and heavy duty charging infrastructure is the subject of a stakeholder process that the BPU began in 2021 and we expect that this effort will result in PSE&G submitting a filing targeting infrastructure investments for the medium and heavy duty EV market. Our CEF-ES program is being held in abeyance. In September 2022, the BPU released a draft Storage Incentive Program (SIP) proposal and is currently undertaking a stakeholder process to receive comments. PSE&G is active in the proceeding.

PSEG Power

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

In August 2021, PSEG entered into two agreements to sell PSEG Power’s 6,750 MW fossil generating portfolio to newly formed subsidiaries of ArcLight Energy Partners Fund VII, L.P., a fund controlled by ArcLight Capital Partners, LLC. In February 2022, PSEG completed the sale of this fossil generating portfolio. These transformative transactions reduce overall business risk and earnings volatility, improve PSEG’s financial flexibility and are consistent with PSEG’s climate strategy and sustainability efforts, which are to focus on clean energy investments, methane reduction, and reducing emissions from our operations in order to transition to carbon-free generation.

PSEG Power’s hedging practices help to manage a significant amount of the earnings volatility of the merchant nuclear power business. More than 90% of PSEG Power’s expected gross margin in 2022 relates to hedging of our energy margin, our expected revenues from the capacity market mechanism, Zero Emission Certificate (ZEC) revenues and, certain gas operations and ancillary service payments such as reactive power. While this limits our exposure to decreasing prices, our ability to realize benefits from rising market prices is also limited. During the second half of 2021 and continuing into 2022, forward energy prices have demonstrated considerable price volatility and have increased dramatically. This has led to significantly higher variation in our collateral requirements, which have also increased substantially over that time period for hedge positions that are out-of-the money. PSEG Power’s net cash collateral postings related to these hedge positions increased from $343 million at the end of June 2021 to $2.2 billion at the end of September 2022. Subsequent to September 2022, collateral postings have decreased but we continued to experience significant fluctuations in our daily collateral requirements. Net cash collateral postings were $1.7 billion as of October 28, 2022. The majority of this collateral relates to hedges in place through the end of 2023 and is expected to be returned as we satisfy our obligations under those contracts. PSEG continues to maintain sufficient liquidity as described in Liquidity and Capital Resources.

Climate Strategy and Sustainability Efforts

For more than a century, our purpose has been to provide safe access to an around-the-clock supply of reliable, affordable energy. Today, our vision is to power a future where people use less energy, and it is cleaner, safer and delivered more reliably than ever. We have established a net zero greenhouse gas (GHG) emissions by 2030 goal that includes direct GHG emissions (Scope 1) and indirect GHG emissions from operations (Scope 2) across our operations, assuming advances in technology, public policy and customer behavior. Scope 1 emissions include power generation, methane leaks, vehicle fleet emissions, and sulfur hexafluoride and refrigerant leaks. Scope 2 emissions include both gas and electric purchased energy for our PSE&G facilities and line losses. We have also committed to the United Nations-backed Race to Zero campaign. We are working toward developing and submitting science-based emission reduction targets following the criteria and recommendations of the Science Based Targets initiative (SBTi) by September 2023. Targets are expected to encompass Scopes 1, 2, and 3 (the majority of which are associated with the downstream use of energy products) and be in line with 1.5oC emissions scenarios in order to be validated by the SBTi.

PSE&G has undertaken a number of initiatives that support the reduction of GHG emissions and the implementation of energy efficiency initiatives. PSE&G’s approved CEF-EE, CEF-Energy Cloud and CEF-EV programs and the proposed CEF-ES program are intended to support New Jersey’s Energy Master Plan through programs designed to help customers increase their energy efficiency, support the expansion of the EV infrastructure in the State, install energy storage capacity to supplement

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solar generation and enhance grid resiliency, install smart meters and supporting infrastructure to allow for the integration of other clean energy technologies and to more efficiently respond to weather and other outage events.

In addition, PSE&G is committed to the safe and reliable delivery of natural gas to almost two million customers throughout New Jersey and we are equally committed to reducing GHG emissions associated with such operations. The first phase of our GSMP replaced approximately 450 miles of cast-iron and unprotected steel gas main infrastructure, and the second phase of this program is expected to replace an additional 875 miles of gas pipes through 2023. The GSMP is designed to significantly reduce natural gas leaks in our distribution system, which would reduce the release of methane, a potent GHG, into the air. Through GSMP II, from 2018 through 2023 we expect to reduce methane leaks by approximately 22% system wide and assuming a continuation of GSMP, we expect to achieve an overall reduction in methane emissions of approximately 60% over the 2011 through 2030 period. As noted previously, in the first quarter of 2023 we anticipate filing for an extension of GSMP which would continue and accelerate these methane reductions. We also continue to assess physical risks of climate change and adapt our capital investment program to improve the reliability and resiliency of our system in an environment of increasing frequency and severity of weather events, notably through our investments in our Energy Strong program and IAP. These investments have proven effective in recent severe weather events, including Tropical Storm Ida in August 2021, which brought significant flooding to our service territory but did not result in the loss of any of our electric distribution substations.

We also continue to focus on providing cleaner energy for our customers. Our priority is to preserve the economic viability of our nuclear units, which provide over 90% of the carbon-free energy in New Jersey, by advocating for state and federal policies, such as the Inflation Reduction Act (IRA) discussed below, that recognize the value of carbon-free generation and reduce market risk. We also continue to explore investment opportunities in offshore wind, both generation and additional transmission solicitations to support the cost-efficient connection of offshore wind generation projects to the New Jersey electric system.

Offshore Wind

In April 2021, PSEG completed its acquisition of a 25% equity interest in Ørsted North America Inc.’s (Ørsted) Ocean Wind 1 project which is currently in development. Ocean Wind 1 was selected by New Jersey to be the first offshore wind farm as part of the State’s intention to add 11,000 MW of offshore wind generating capacity by 2040. The Ocean Wind 1 project is expected to achieve full commercial operation in 2025.

PSEG’s continuation as an equity owner of the Ocean Wind 1 project is subject to its final investment decision (FID), which represents the decision to proceed to the construction phase of the project. Each of Ørsted and PSEG is expected to make its own decision on whether to take FID. If PSEG chooses not to proceed with the project and Ørsted determines to proceed, Ørsted is required to purchase PSEG’s 25% equity interest. PSEG is reviewing its options regarding the status of PSEG’s equity investment in the project and the final outcome cannot be determined at this time.

Additionally, PSEG and Ørsted each owns 50% of Garden State Offshore Energy LLC (GSOE) which holds rights to an offshore wind lease area just south of New Jersey. In December 2021, the Maryland Public Service Commission awarded Ørsted’s 846 MW Skipjack 2 project Offshore Renewable Energy Credits under Maryland’s second round of offshore wind solicitations. Skipjack 2 utilizes a portion of the GSOE lease area, and PSEG has an option to purchase 50% of Skipjack 2 and the previously awarded 120 MW Skipjack 1 project, which will be constructed concurrently. PSEG is in the process of determining whether or not to exercise this option and is exploring other options relating to the remaining GSOE lease area.

In April 2021, PJM announced the opening of the first public policy Order 1000 bid window that would utilize the state agreement approach for transmission projects to support New Jersey’s planned offshore wind generation. The state agreement approach requires customers in the requesting state - in this case New Jersey - to pay for the costs of these public policy transmission projects. In September 2021, PSEG and Ørsted jointly submitted several proposals in response to the solicitation, including multi-spur options and an offshore network proposal. The BPU completed its review of offshore wind transmission in October 2022 and awarded several on-shore solutions. PSE&G was awarded $40 million for transmission upgrades. The BPU also indicated that it would consider conducting an additional solicitation to address the State’s increased offshore wind generation targets.

Ongoing Coronavirus Pandemic

As a result of the COVID-19 pandemic, we have incurred additional expenses to protect our employees and customers. The pandemic 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 Conservation Incentive Program (CIP) that became effective in 2021. The most substantive impact of the pandemic has been adverse changes to residential and C&I payment patterns as the State of New Jersey has imposed a moratorium on non-safety related service disconnections for non-payment since March 2020 through mid-March 2022. While collections and shut-offs re-commenced after the moratorium ended, the State passed legislation that provided protection from shut-offs to customers who applied for payment assistance programs by June 15, 2022. Those

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applying for assistance will be protected from shut-offs while awaiting their application determination. As a result, since March 2020, PSE&G experienced a significant decrease in cash inflow and higher Accounts Receivable aging and an associated increase in bad debt expense, which we expect will take the next several years to fully return to normal levels. Over that time, PSE&G’s allowance for credit losses has increased by approximately $264 million. PSE&G’s electric distribution bad debt expense is recoverable through its Societal Benefits Clause (SBC) mechanism. PSE&G has deferred its incremental gas distribution bad debt expense as a result of COVID-19 as a Regulatory Asset and will seek recovery of that cost, as well as other net incremental COVID-19 costs, in its next base rate case.

The BPU has authorized regulated utilities in New Jersey, including PSE&G, to defer prudently incurred incremental costs related to COVID-19 beginning on March 9, 2020 through December 31, 2022 for recovery in a future rate case. The BPU is currently evaluating PSE&G’s request to extend the deferral to December 2023. The BPU is also conducting a generic proceeding related to the treatment and potential recovery of costs related to COVID-19. 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, 2022, PSE&G has recorded a Regulatory Asset related to COVID-19 to defer incremental costs of $122 million, which PSE&G believes are recoverable under the BPU Order.

The potential future impact of the pandemic and the associated economic impacts, which could extend beyond the duration of the pandemic, will depend on a number of factors outside of our control. These include the duration and severity of the outbreaks as well as third-party actions taken to contain their spread and mitigate their public health effects, and governmental or regulatory actions regarding customer collections, potential limitations on rate increases, recovery of costs, and other matters. We cannot estimate the ultimate impact to our results of operations, financial condition and cash flows.

Operational Excellence

In 2022, PSE&G continued its efforts to control costs while maintaining strong operational performance. PSE&G’s safety and reliability metrics continue to achieve top decile results as compared to our peer group. We also seek to achieve operational excellence and manage costs in order to optimize cash flow generation from our nuclear fleet in light of volatile wholesale power and gas prices, environmental considerations and competitive market forces that support safety, efficiency and reliability. During the first nine months of 2022, our nuclear units generated 23.9 terawatt hours and operated at a capacity factor of 94.3%.

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 2022 as we

maintained sufficient liquidity, including the extension of the expiration of our revolving credit facilities from March 2024 to March 2027,
completed the sale of PSEG Power’s 6,750 MW portfolio of fossil generation assets,
maintained solid investment grade credit ratings, and
increased our indicative annual dividend per share for 2022 to $2.16.

In 2021, the Board of Directors authorized senior management to implement a $500 million share repurchase program. In December 2021, under this authorization, we entered into an open market share repurchase plan for $250 million of our common shares. During January and through mid-February 2022, we purchased the full $250 million of common shares under the open market share repurchase plan. In March 2022, under this authorization, PSEG entered into an accelerated share repurchase agreement for $250 million of our common shares which was completed in May 2022. See Item 1. Note 18. Earnings Per Share (EPS) and Dividends for additional information.

We expect to be able to fund our planned capital requirements, as described in Liquidity and Capital Resources without the issuance of new equity. Our planned capital requirements, which are driven by growth in our regulated utility, and the sale of our fossil generating fleet enhances our business profile and underpins solid investment grade credit ratings with improved financial flexibility.

The current inflationary environment has prompted the Federal Reserve to tighten monetary policy resulting in higher interest rates, which have impacted financial markets, reducing the value of fixed income investments and created uncertainty about the future economic outlook weakening equity markets. These factors have resulted in negative returns on our pension assets during 2022. As our pension costs are set at the beginning of the calendar year, there is no impact on pension costs for 2022 resulting from asset performance during the year. However, pension costs in future years may be materially impacted, depending on pension fund performance for 2022. The higher interest rates translate into a higher discount rate for our pension obligations, which would lower our pension liability and positively affect our funded ratio, which is expected to remain strong.

In September 2022, PSE&G filed a petition with the BPU to mitigate some of the volatility in earnings related to our pension

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trust performance. The petition requests an accounting order from the BPU, effective January 1, 2023, to authorize PSE&G to modify its method for calculating the amortization of the net actuarial gain or loss component of pension expense for ratemaking purposes by deferring the recognition of the difference between expected and actual returns into the net actuarial gain or loss ratably over a five-year period. We cannot predict the outcome of this matter.

Further, higher interest rates on borrowings will contribute to higher interest expense on variable rate debt, which has increased due to cash collateral postings, and to long-term rates on future financing plans. During September and October 2022, PSEG entered into floating-to-fixed interest rate swaps totaling $1,050 million in order to reduce the volatility in interest expense for a portion of our variable-rate debt at PSEG and PSEG Power. Inflation will also result in upward pressure on operating costs and capital spending. In addition, energy supply costs are a pass-through putting upward pressure on utility customer bills, which could be an area of focus with regulators.

Financial Results

The results for PSEG, PSE&G and PSEG Power for the three months and nine months ended September 30, 2022 and 2021 are presented as follows:



	Three Months Ended				Nine Months Ended
	September 30,				September 30,
Earnings (Losses)	2022		2021		2022		2021
	Millions
PSE&G	$	399	$	389	$	1,213	$	1,175
PSEG Power (A)	(241)		(1,933)		(922)		(2,255)
Other (B)	(44)		(20)		(48)		(13)
PSEG Net Income (Loss)	$	114	$	(1,564)	$	243	$	(1,093)

PSEG Net Income (Loss) Per Share (Diluted)	$	0.22	$	(3.10)	$	0.48	$	(2.17)

(A)Includes an after-tax loss and other charges of $1,563 million for the three months and $1,936 million for the nine months ended September 30, 2021, respectively, related to the sale of PSEG Power’s Fossil generating assets. See Item 1. Note 4. Early Plant Retirements/Asset Dispositions and Impairments.

(B)Other includes after-tax activities at the parent company, PSEG LI, and Energy Holdings as well as intercompany eliminations. Includes a $38 million after-tax impairment of assets related to one of Energy Holdings’ generating facilities for the three and nine months ended September 30, 2022. See Item 1. Note 4. Early Plant Retirements/Asset Dispositions and Impairments.

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 (Loss) 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,
	2022		2021		2022		2021
	Millions, after tax
NDT Fund Income (Expense) (A) (B)	$	(61)	$	(11)	$	(224)	$	68
Non-Trading MTM Gains (Losses) (C)	$	(214)	$	(478)	$	(896)	$	(718)

(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 $37 million and $5 million for the three months and $131 million and $(48) million for the nine months ended September 30, 2022 and 2021, respectively.

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(C)Net of tax (expense) benefit of $83 million and $188 million for the three months and $350 million and $280 million for the nine months ended September 30, 2022 and 2021, respectively.

Our Net Income for the three months ended September 30, 2022 as compared to the Net Loss in the comparable period in 2021 was driven primarily by:

lower MTM losses in 2022 due to a more significant increase in energy prices in 2021, and
an impairment loss related to the pending February 2022 sale of the fossil generating assets at PSEG Power in 2021 (see Item 1. Note 4. Early Plant Retirements/Asset Dispositions and Impairments for additional information),
partially offset by higher net losses on NDT Fund equity securities in 2022 and net realized losses in 2022 as compared to gains in 2021, and
an impairment of the assets related to one of Energy Holdings’ energy generating facilities in 2022.

Our Net Income for the nine months ended September 30, 2022 as compared the Net Loss in the comparable period in 2021 was driven primarily by

an impairment loss related to the sale of the fossil generating assets at PSEG Power in 2021 (see Item 1. Note 4. Early Plant Retirements/Asset Dispositions and Impairments for additional information),
higher earnings in 2022 due to continued investments in T&D programs at PSE&G, and
the favorable impact of the CIP in 2022 at PSE&G,
partially offset by higher MTM losses in 2022 at PSEG Power due to rising energy prices principally in the first quarter of 2022,
net unrealized losses on equity securities in 2022 in the NDT Fund and net realized losses in 2022 as compared to net realized gains in 2021, and
an impairment of the assets related to one of Energy Holdings’ energy generating facilities in 2022.

Disciplined Investment

We utilize rigorous criteria and consider a number of external factors, focusing on the value for our investors and other key 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 2022, 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,
obtained approval for our IAP and filed for an extension of our CEF-EE program, and
continued to evaluate potential offshore wind opportunities.

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 Report on Form 10-Q for the period ending June 30, 2022 and in this Quarterly Report on Form 10-Q.

Transmission Rate Proceedings and Return on Equity (ROE)

In October 2021, FERC approved a settlement agreement effective August 1, 2021 that we reached with the BPU and the New Jersey Division of Rate Counsel about the level of PSE&G’s base transmission ROE and other formula rate matters. The settlement reduces PSE&G’s base ROE from 11.18% to 9.9% and makes several other changes regarding the recovery of certain costs. The agreement provides that the settling parties will not seek changes to our transmission formula rate for three years. We have implemented the terms of the agreement and PJM issued refunds to customers in January 2022.

Under current FERC rules, we continue to earn a 50 basis point adder to that base ROE for our membership in PJM. FERC is reconsidering this adder and the outcome and timing of any decision is uncertain. Elimination of the adder for Regional Transmission Organization membership could reduce PSE&G’s annual Net Income and annual cash inflows by approximately $30 million to $40 million.

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Wholesale Power Market Design

FERC issued a notice effective September 2021 that essentially put into effect a new Minimum Offer Price Rule (MOPR) that would accommodate certain state public policy programs. PSEG Power’s New Jersey nuclear plants that receive ZEC payments were not subject to the MOPR in the June 2022 Base Residual Auction. These new MOPR rules are being challenged by a group of generators in the Court of Appeals for the Third Circuit. PSEG has intervened in the proceeding in support of the new MOPR rules. We cannot predict the outcome of this proceeding.

A factor that influenced the results of the June base residual auction was FERC’s 2021 order related to the Market Seller Offer Cap which ultimately eliminated the default offer cap. In its place, FERC adopted a unit-specific approach to reviewing certain capacity market offers. These new rules, which require market offers for many resource types to be approved by the Independent Market Monitor and PJM resulted in lower capacity prices in the June auction.

In July 2021, the BPU issued a report on its investigation related to whether New Jersey can achieve its long-term clean energy and environmental objectives under the current resource adequacy procurement paradigm. The report found that participating in the regional market is the most efficient way for New Jersey to achieve its clean energy goals and therefore consideration of leaving the regional market is paused while market reforms are being considered at the regional and national level. In September 2022, the BPU issued a Progress Report expanding on the recommendations contained in the 2021 report. The Progress Report found that it is in New Jersey’s best interest to pursue a voluntary independent clean energy market and sought the BPU’s authorization to evaluate various options that would serve as alternatives to the PJM capacity market or work in conjunction with it. We cannot predict whether the BPU will ultimately take any measures in the future that will have an impact on the capacity market or our generating stations.

Environmental Regulation

We are subject to liability under environmental laws for the costs and penalties of remediating contamination of property now or formerly owned by us and of property contaminated by hazardous substances that we generated. In particular, the historic operations of PSEG companies and the operations of numerous other companies along the Passaic and Hackensack Rivers are alleged by federal and state agencies to have discharged substantial contamination into the Passaic River/Newark Bay Complex in violation of various statutes. In addition, PSEG Power has retained 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 (ISRA) and the Connecticut Transfer Act (CTA). We are currently conducting investigations under ISRA and the CTA and we anticipate that these investigations could take several years before the full remediation costs are estimable. 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 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 megawatt hour (MWh) received during the prior ZEC period through May 2022. 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 MWh generated in payments to selected nuclear plants (ZEC payment)). In August 2022, the Inflation Reduction Act (IRA) was signed into law expanding incentives promoting carbon-free generation. The enacted legislation established the production tax credit (PTC) for electricity generation using nuclear energy set to begin in 2024 through 2032. The expected PTC rate is up to $15/MWh subject to adjustment based upon a facility’s gross receipts. The PTC rate and the gross receipts cap are subject to annual inflation adjustments. The U.S. Treasury is expected to clarify the definition of gross receipts prior to when the eligibility period begins in 2024. We are continuing to analyze the impact of the IRA on our nuclear units including additional future guidance from the U.S. Treasury and the interactions with PTCs on expected ZEC payments. See Item 1. Note 4. Early Plant Retirements/Asset Dispositions and Impairments for additional information.

Tax Legislation

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

The IRA made certain changes to the energy tax credit law and enacted a new 15% book minimum tax. The IRA, as discussed, enacts a PTC for existing nuclear generation facilities. It also increases the renewable PTC, imposes a new wage and apprenticeship requirement, expands technologies that are eligible for a tax credit, allows tax credits to be transferable and provides an enhanced credit if steel and iron are sourced from the U.S. and a certain percentage of manufactured components

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are constructed in the U.S., among other things. Many aspects of the IRA are unclear and in need of further guidance. Until additional guidance is issued, the impact that the IRA has on PSEG’s and PSE&G’s financial statements is not determinable.

The Consolidated Appropriations Act, 2021 (CAA), enacted in late December 2020, provides a 30% investment tax credit (ITC) for offshore wind projects that begin construction before December 31, 2025. In addition, on December 31, 2020, Notice 2021-05 was issued. For qualifying offshore wind projects, the notice extends the four year continuity safe harbor to ten calendar years commencing the calendar year after which construction of the project begins. Subject to potential additional legislation, the CAA and the associated 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. The portion of PSEG’s and PSEG Power’s business interest expense that was disallowed in 2018 and 2019 is now deductible in those respective years. For 2022 and after, the regulations disallow the addback of depreciation in the computation of ATI, effectively lowering the cap on the amount of deductible business interest. We do not believe this change will result in limitations on the deductible business interest expense of PSEG and PSEG Power.

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,
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,
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 appropriate regulatory guidance on the federal nuclear PTC to ensure long-term support for New Jersey’s largest carbon-free generation resource, as well as a complementary state program to ensure long-term viability of these facilities consistent with state climate policy,
engage constructively with our multiple stakeholders, including regulators, government officials, customers, employees, investors, suppliers and the communities in which we do business,
seek a fair return for our T&D investments through our transmission formula rate, distribution infrastructure and clean energy investment programs and periodic distribution base rate case proceedings, and
successfully operate the LIPA T&D system and manage LIPA’s fuel supply and generation dispatch obligations.

In addition to the risks described elsewhere in this Form 10-Q and in our Form 10-K, for 2022 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, the role of distribution utilities and decarbonization impacts, 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, including continued supply chain constraints and increases in the cost of goods and services, which could extend beyond the duration of the pandemic,
the current inflationary environment and associated volatility in the financial and commodity markets,

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increases in commodity prices and customer rates, which may adversely affect customer collections and future regulatory proceedings,
future changes in federal and state tax laws or any other associated tax guidance, and
the impact of changes in demand, natural gas and electricity prices, and expanded efforts to decarbonize several sectors of the economy.

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

investments in PSE&G, including T&D facilities to enhance reliability, resiliency and modernize the system to meet the growing needs and increasingly higher expectations of customers, and clean energy investments such as CEF-EE, CEF-EV, CEF-ES and Solar,
investments in regional offshore wind with long-term contracts or regulated transmission returns that provide revenue predictability and a reasonable risk-adjusted return,
continued operation of our nuclear generation facilities, to the extent there is sufficient certainty that their operation will render an acceptable risk-adjusted return, and
acquisitions, dispositions, development 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 segments, PSE&G and PSEG Power, excluding charges related to intercompany transactions, which are eliminated in consolidation. For additional information on intercompany transactions, see Item 1. Note 20. Related-Party Transactions.



	Three Months Ended				Increase/ (Decrease)				Nine Months Ended				Increase/ (Decrease)
	September 30,						September 30,
	2022		2021		2022 vs. 2021				2022		2021		2022 vs. 2021
	Millions				Millions			%	Millions				Millions		%
Operating Revenues	$	2,272	$	1,903	$	369		19	$	6,661	$	6,666	$	(5)	—
Energy Costs	1,012		860		152			18	3,022		2,495		527		21
Operation and Maintenance	765		807		(42)			(5)	2,310		2,368		(58)		(2)
Depreciation and Amortization	270		283		(13)			(5)	822		946		(124)		(13)
(Gains) Losses on Asset Dispositions and Impairments	52		2,158		(2,106)			(98)	90		2,615		(2,525)		(97)
Income from Equity Method Investments	5		3		2			67	16		12		4		33
Net Gains (Losses) on Trust Investments	(97)		(17)		(80)			N/A	(352)		124		(476)		N/A
Other Income (Deductions)	43		35		8			23	86		93		(7)		(8)
Net Non-Operating Pension and OPEB Credits (Costs)	94		82		12			15	282		246		36		15
Interest Expense	163		144		19			13	450		437		13		3
Income Tax (Benefit) Expense	(59)		(682)		623			(91)	(244)		(627)		383		(61)

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,
	2022		2021		2022 vs. 2021				2022		2021		2022 vs. 2021
	Millions				Millions			%	Millions				Millions		%
Operating Revenues	$	1,953	$	1,820	$	133		7	$	5,905	$	5,407	$	498	9
Energy Costs	791		698		93			13	2,389		2,056		333		16
Operation and Maintenance	452		422		30			7	1,349		1,239		110		9
Depreciation and Amortization	229		226		3			1	697		698		(1)		—
Gain on Asset Dispositions	1		4		(3)			(75)	1		4		(3)		(75)
Net Gains (Losses) on Trust Investments	—		—		—			—	(2)		1		(3)		N/A
Other Income (Deductions)	25		20		5			25	66		72		(6)		(8)
Net Non-Operating Pension and OPEB Credits (Costs)	70		67		3			4	211		199		12		6
Interest Expense	109		102		7			7	319		301		18		6
Income Tax Expense (Benefit)	69		74		(5)			(7)	214		214		—		—

Three Months Ended September 30, 2022 as Compared to Three Months Ended September 30, 2021

Operating Revenues increased $133 million due to changes in delivery, commodity, clause and other operating revenues.

Delivery Revenues increased $25 million due primarily to

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Electric distribution revenues increased $17 million due to $18 million from higher sales volumes and $10 million from Energy Strong II collections. These increases were partially offset by an $8 million decrease in CIP decoupling and a $3 million decrease in Green Program Recovery Charge (GPRC) collections.
Gas distribution revenues increased $5 million due primarily to increases of $6 million from CIP decoupling and $4 million in GSMP II collections, partially offset by a $4 million decrease due to lower sales volumes.
Electric and Gas distribution revenues also increased $2 million due to a net decrease 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.
Transmission revenues were $1 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.

Commodity Revenues increased $73 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 basic generation service (BGS) to retail customers and basic gas supply service (BGSS).

Electric commodity revenues increased $54 million due to a $73 million increase in sales volumes, partially offset by a $19 million decrease from lower BGS prices.
Gas commodity revenues increased $19 million due primarily to $23 million from higher BGSS prices, partially offset by a $5 million decrease from lower BGSS sales volumes.

Clause Revenues increased $9 million due primarily to higher SBC revenues of $12 million partially offset by a $4 million decrease in Tax Adjustment Credit (TAC) and GPRC deferrals. The changes in SBC revenues and 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 SBC revenue or TAC and GPRC deferrals.

Other Operating Revenues increased $26 million due primarily to revenue from the Successor Solar Incentive (SuSi) Program and appliance services. The SuSi component of Other Operating Revenues is entirely offset by changes to Energy Costs.

Operating Expenses

Energy Costs increased $93 million. This is primarily offset by changes in Commodity Revenues and Other Operating Revenues.

Operation and Maintenance increased $30 million due primarily to increases of $24 million in clause and renewable-related expenses, $7 million due to higher service company costs, $5 million in injuries and damages and $2 million in higher transmission costs. These increases were partially offset by $8 million of lower distribution operational costs including lower storm costs.

Depreciation and Amortization increased $3 million due primarily to an $11 million increase related to additional plant placed in service, partially offset by a $5 million decrease in the amortization of Regulatory Assets and a $4 million decrease from new lower transmission depreciation rates that became effective in August 2021.

Other Income (Deductions) increased $5 million due primarily to a $3 million increase in investment income and a $2 million increase in the equity portion of the allowance for funds used during construction (AFUDC).

Net Non-Operating Pension and OPEB Credits (Costs) increased $3 million due primarily to a $12 million decrease in the amortization of the net actuarial loss, partially offset by a $5 million decrease in the expected return on plan assets and a $4 million increase in interest cost.

Interest Expense increased $7 million due primarily to net debt issuances in 2022 and 2021.

Income Tax Expense decreased $5 million due primarily to tax benefits from increased CEF program investments in 2022.

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Nine Months Ended September 30, 2022 as Compared to Nine Months Ended September 30, 2021

Operating Revenues increased $498 million due to changes in delivery, commodity, clause and other operating revenues.

Delivery Revenues increased $137 million due primarily to

Gas distribution revenues increased $81 million due primarily to increases of $39 million from CIP decoupling, $37 million in GSMP II collections, $4 million due to higher sales volumes and $1 million in GPRC collections.
Electric distribution revenues increased $47 million due primarily to $20 million from Energy Strong II collections, $19 million from CIP decoupling and $10 million from higher sales volumes, partially offset by a decrease of $2 million in GPRC collections.
Electric and Gas distribution revenues also increased $20 million due to a net decrease 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.
Transmission revenues were $11 million lower due primarily to the estimated impact of the ROE settlement, partially offset by an increase in revenue requirements attributable to higher rate base investment.

Commodity Revenues increased $311 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 $195 million due primarily to $186 million from higher BGSS prices and $9 million from higher BGSS sales volumes.
Electric commodity revenues increased $116 million due primarily to a $102 million increase from higher sales volumes and $16 million in higher BGS prices.

Clause Revenues increased $3 million due primarily to higher SBC revenues of $28 million, partially offset by a $24 million decrease in TAC deferrals and a $1 million decrease in GPRC deferrals. The changes in SBC revenues 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 revenue or TAC and GPRC deferrals.

Other Operating Revenues increased $47 million due primarily to revenue increases in appliance services, the SuSi Program and Solar Renewable Energy Certificates (SREC). The SuSi and SREC components of Other Operating Revenues are entirely offset by changes to Energy Costs.

Operating Expenses

Energy Costs increased $333 million. This is primarily offset by changes in Commodity Revenues and Other Operating Revenues.

Operation and Maintenance increased $110 million due primarily to increases of $61 million in clause and renewable-related expenses, $14 million in injuries and damages, $11 million increase from higher service company costs, $10 million in electric distribution operational costs net of lower storm costs, $4 million in appliance service competitive services costs and $13 million of other support costs. These increases were partially offset by $3 million of lower transmission costs.

Depreciation and Amortization decreased $1 million due primarily to a $28 million decrease due to new lower transmission depreciation rates that became effective in August 2021 and a $17 million decrease in the amortization of Regulatory Assets, nearly offset by a $41 million increase related to additional plant placed in service and a $2 million increase in the amortization of software.

Other Income (Deductions) decreased $6 million due primarily to an $11 million decrease in the equity portion of the AFUDC, partially offset by a $5 million increase in investment income.

Net Non-Operating Pension and OPEB Credits (Costs) increased $12 million due primarily to a $38 million decrease in the amortization of the net actuarial loss, partially offset by a $16 million decrease in the expected return on plan assets and a $10 million increase in interest cost.

Interest Expense increased $18 million due primarily to a $9 million increase from the 2022 debt issuance, a $4 million increase in commitments and other fees, a $3 million increase in AFUDC and a $2 million increase from net debt issuances in 2021.

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PSEG Power



	Three Months Ended				Increase/ (Decrease)				Nine Months Ended				Increase/ (Decrease)
	September 30,						September 30,
	2022		2021		2022 vs. 2021				2022		2021		2022 vs. 2021
	Millions				Millions			%	Millions				Millions		%
Operating Revenues	$	266	$	51	$	215		N/A	$	1,214	$	1,598	$	(384)	(24)
Energy Costs	335		290		45			16	1,568		1,243		325		26
Operation and Maintenance	179		230		(51)			(22)	565		711		(146)		(21)
Depreciation and Amortization	34		50		(16)			(32)	103		225		(122)		(54)
(Gains) Losses on Asset Dispositions and Impairments	—		2,162		(2,162)			N/A	38		2,619		(2,581)		(99)
Income from Equity Method Investments	5		3		2			67	15		12		3		25
Net Gains (Losses) on Trust Investments	(96)		(17)		(79)			N/A	(344)		120		(464)		N/A
Other Income (Deductions)	16		16		—			—	16		20		(4)		(20)
Net Non-Operating Pension and OPEB Credits (Costs)	17		12		5			42	52		35		17		49
Interest Expense	17		19		(2)			(11)	32		70		(38)		(54)
Income Tax Expense (Benefit)	(116)		(753)		637			(85)	(431)		(828)		397		(48)

Three Months Ended September 30, 2022 as Compared to Three Months Ended September 30, 2021

Operating Revenues increased $215 million due primarily to changes in generation and gas supply revenues.

Gas Supply Revenues increased $188 million due primarily to

an increase of $122 million related to sales to third parties, primarily due to higher sales prices of $96 million and higher sales volumes of $26 million,
a net increase of $39 million in sales under the BGSS contract due primarily to higher prices of $43 million, partially offset by lower sales volumes of $4 million, and
an increase of $27 million due to lower MTM losses in 2022 as compared to 2021 due primarily to changes in forward prices.

Generation Revenues increased $25 million due primarily to

a net increase of $399 million due to lower MTM losses in 2022 as compared to 2021. Of this amount, there was a $204 million increase due to changes in forward prices in 2022 as compared to 2021 coupled with a $195 million increase due to higher gains on positions reclassified to realized upon settlement in 2022 as compared to losses in 2021,
partially offset by a net decrease of $232 million due primarily to lower volumes sold in the PJM, New England (NE) and New York (NY) regions primarily due to the sale of the fossil generating plants, coupled with lower average realized prices in the PJM region,
a net decrease of $77 million in capacity revenue due primarily to the sale of the fossil generating plants coupled with lower capacity prices in the PJM region, partially offset by decreases in capacity expenses due to lower load volumes served, and
a net decrease of $60 million due primarily to lower volumes of electricity sold under the BGS contracts.

Other Operating Revenues increased $2 million due primarily to changes in generation and gas supply revenues.

Operating Expenses

Energy Costs represent the cost of generation, which includes fuel costs for generation as well as purchased energy in the market, and gas purchases to meet PSEG Power’s obligation under its BGSS contract with PSE&G. Energy Costs increased $45 million due to

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Gas costs increased $157 million due mainly to

a net increase of $113 million related to sales to third parties, primarily due to increases in the average cost of gas of $89 million and volumes sold of $24 million, and
a net increase of $44 million primarily related to sales under the BGSS contract, of which $47 million was due to the higher average cost of gas, partially offset by $3 million due to lower send out volumes.

Generation costs decreased $112 million due primarily to

a net decrease of $156 million in fuel costs due to the sale of the fossil generating plants, and
a net decrease of $14 million in energy purchases due primarily to lower renewable energy credit (REC) requirements caused by decreases in load served in the PJM and NE regions,
partially offset by a net increase of $58 million due to MTM gains in 2021 as compared to flat activity in 2022. Of this amount, there was an $88 million increase due to changes in forward prices, partially offset by a $30 million decrease due to higher gains on positions reclassified to realized upon settlement in 2022 as compared to 2021.

Operation and Maintenance decreased $51 million due primarily to the sales of the fossil generating plants in February 2022. The decrease was partially offset by a refueling outage at our 100%-owned Hope Creek nuclear plant in 2022 as compared to a refueling outage at our 57%-owned Salem 1 nuclear plant in 2021.

Depreciation and Amortization decreased $16 million due primarily to ceasing depreciation expense on the then pending sale of the fossil generating plants since August 2021.

(Gains) Losses on Asset Dispositions and Impairments reflects an impairment loss on the fossil generating assets in 2021. See Item 1. Note 4. Early Plant Retirements/Asset Dispositions and Impairments.

Net Gains (Losses) on Trust Investments decreased $79 million due primarily to NDT investments with $25 million of net realized losses in 2022 as compared to $15 million of net realized gains in 2021 and an increase of $37 million of unrealized losses on equity securities as compared to 2021.

Non-Operating Pension and OPEB Credits (Costs) increased $5 million due to an increase in the expected return on plan assets and a decrease in the amortization of the net actuarial loss, partially offset by an increase in interest cost and co-owner charges.

Interest Expense decreased $2 million due primarily to the early redemption of all outstanding Senior Notes in October 2021, partially offset by a term loan entered into in March 2022.

Income Tax (Benefit) decreased $637 million due primarily to a lower pre-tax loss in 2022, partially offset by increased tax benefits in 2022 on losses from the NDT qualified fund.

Nine Months Ended September 30, 2022 as Compared to Nine Months Ended September 30, 2021

Operating Revenues decreased $384 million due primarily to changes in generation and gas supply revenues.

Generation Revenues decreased $949 million due primarily to

a net decrease of $460 million due primarily to lower volumes sold in the PJM, NE and NY regions primarily due to the sale of the fossil generating plants, coupled with lower average realized prices in the PJM region, partially offset by higher average realized prices in the NE and NY regions,
a net decrease of $141 million due to higher MTM losses in 2022 as compared to 2021. Of this amount, there was a $425 million decrease due to changes in forward prices, partially offset by a $284 million increase due to gains on positions reclassified to realized upon settlement in 2022 as compared to losses in 2021,
a net decrease of $175 million due primarily to lower volumes of electricity sold under the BGS contracts, partially offset by less transmission services under the BGS contracts that were transferred from the BGS suppliers to the Electric Distribution Companies (EDCs) in February 2021,
a net decrease of $136 million in capacity revenue due primarily to the sale of the fossil generating plants coupled with lower capacity prices in the PJM region, partially offset by decreases in capacity expenses due to lower load volumes served,
a net decrease of $24 million in solar revenues due to the sale of the solar plants in June 2021, and
a net decrease of $17 million in ancillary revenues due primarily to the sale of the fossil generating plants.

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Gas Supply Revenues increased $565 million due primarily to

a net increase of $274 million in sales under the BGSS contract due primarily to higher prices of $262 million and higher sales volumes of $12 million,
a net increase of $245 million related to sales to third parties, primarily due to higher sales prices of $215 million and higher sales volumes of $30 million, and
an increase of $46 million due to lower MTM losses in 2022 as compared to 2021 due primarily to changes in forward prices.

Operating Expenses

Gas costs increased $507 million due mainly to

a net increase of $284 million primarily related to sales under the BGSS contract, of which $275 million was due to the higher average cost of gas and $9 million to higher send out volumes, and
a net increase of $222 million related to sales to third parties, of which $195 million was due to an increase in the average cost of gas and $27 million to higher volumes sold.

Generation costs decreased $182 million due primarily to

a net decrease of $231 million in fuel costs, primarily due to lower volumes of gas used in the PJM, NY, and NE regions caused by the sale of the fossil generating plants, partially offset by higher gas prices. Additionally, there was a decrease in coal costs in the NE region due to the retirement of the Bridgeport Harbor 3 (BH3) plant in 2021,
a net decrease of $64 million in energy purchases due primarily to lower REC requirements and lower ancillary charges caused by decreases in load served in the PJM and NE regions,
a net decrease of $22 million in emission costs due to the sale of the fossil generating plants, and
a net decrease of $14 million in transmission costs due primarily to the impact from transfer of responsibility for firm transmission services under BGS contracts from BGS suppliers to the EDCs,
partially offset by a net increase of $151 million due to net MTM losses in 2022 as compared to net MTM gains in 2021. Of this amount, there was a $111 million increase in losses due to changes in forward prices coupled with a $40 million increase in losses due to higher gains on positions reclassified to realized upon settlement in 2022.

Operation and Maintenance decreased $146 million due primarily to the sale of the fossil generating plants in February 2022 and the sale of our ownership interest in the solar plants in June 2021.

Depreciation and Amortization decreased $122 million due primarily to ceasing depreciation expense on the then pending sales of the solar and fossil generating plants since May and August 2021, respectively, and the retirement of BH3 in 2021, partially offset by higher depreciation directly related to an increase in the nuclear Asset Retirement Obligations in 2021.

(Gains) Losses on Asset Dispositions and Impairments in 2022 reflects an impairment loss due to the sale of the fossil generating plants in February 2022. The $2,619 million net loss in 2021 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. See Item 1. Note 4. Early Plant Retirements/Asset Dispositions and Impairments.

Net Gains (Losses) on Trust Investments decreased $464 million due primarily to NDT investments with an increase of $281 million of unrealized losses on equity securities as compared to 2021 and $40 million of net realized losses in 2022 as compared to $139 million of net realized gains in 2021.

Non-Operating Pension and OPEB Credits (Costs) increased $17 million due to an increase in the expected return on plan assets and a decrease in the amortization of the net actuarial loss, partially offset by an increase in interest cost and co-owner charges.

Interest Expense decreased $38 million due primarily to the early redemption of all outstanding Senior Notes in 2021, partially offset by a term loan entered into in March 2022.

Income Tax (Benefit) decreased $397 million due primarily to a lower pre-tax loss in 2022, partially offset by the recapture of ITCs related to the sale of Solar Source in June 2021 and increased tax benefits on losses from the NDT qualified fund.

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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, 2022, our operating cash flow decreased $477 million as compared to the same period in 2021. The net decrease was primarily due to a $372 million reduction related to net cash collateral posting requirements at PSEG Power and a net change at PSE&G, as discussed below. In addition, there were tax payments in 2022 as compared to tax refunds in 2021 at Energy Holdings and lower tax refunds in 2022 at the parent company.

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 increased $303 million from $1,283 million to $1,586 million for the nine months ended September 30, 2022, as compared to the same period in 2021, due primarily to higher cash collateral postings received from BGS suppliers, a reduction in accounts receivable and unbilled revenues in 2022, decreases in electric energy and vendor payments, higher tax payments in 2021 and higher earnings in 2022, partially offset by a net increase in regulatory deferrals in 2022.

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.

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.

During the second half of 2021 and continuing into 2022, forward energy prices have demonstrated considerable price volatility and have increased dramatically. This has led to significantly higher variation in our daily collateral requirements which have also increased substantially over that time period for hedge positions that are out-of-the money. PSEG Power’s net cash collateral postings related to these hedge positions increased from $343 million at the end of June 2021 to $2.2 billion at the end of September 2022. Subsequent to September 2022, collateral postings have decreased but PSEG Power continued to experience significant fluctuations in its daily collateral requirements. Net cash collateral postings were $1.7 billion as of October 28, 2022. The majority of this collateral relates to hedges in place through the end of 2023 and is expected to be returned as we satisfy our obligations under those contracts. Proceeds from the sale of Fossil, the closing of a $1.25 billion term loan in March 2022 at PSEG Power, and short-term borrowings at PSEG have contributed to available liquidity to help support PSEG Power’s current collateral requirements in 2022.

In March and May 2021, PSEG entered into two 364-day variable rate term loan agreements for $500 million and $750 million, respectively. In August 2021, PSEG entered into a $1.25 billion, 364-day variable rate term loan agreement. In March 2022, the $500 million term loan matured and PSEG prepaid the $750 million term loan due in May 2022. In July 2022, PSEG repaid the $1.25 billion term loan due in August 2022. These term loans are not included in the credit facility amounts presented in the following table.

In April 2022 and May 2022, PSEG entered into 364-day variable rate term loan agreements for $1.5 billion and $500 million, respectively.

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Our total committed credit facilities and available liquidity as of September 30, 2022 were as follows:



Company/Facility	As of September 30, 2022
Total Facility	Usage		Available Liquidity
	Millions
PSEG	$	1,500	$	237	$	1,263
PSE&G	1,000		18		982
PSEG Power	1,650		489		1,161
Total	$	4,150	$	744	$	3,406

We continually monitor our liquidity and seek to add capacity as needed to meet our liquidity requirements, including to satisfy any additional collateral requirements. As of September 30, 2022, our liquidity position, including our credit facilities and access to external financing, was expected to be sufficient to meet our projected stressed requirements over our 12 month planning horizon. PSEG analyzes its liquidity requirements using stress scenarios that consider different events, including 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 $917 million and $1,151 million as of September 30, 2022 and December 31, 2021, respectively.

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

Long-Term Debt Financing

During the next twelve months,

PSEG has $700 million of 2.65% Senior Notes maturing in November 2022,
PSE&G has $500 million of 2.38% Medium-Term Notes, Series I, due May 2023, and
PSE&G has $325 million of 3.25% Medium-Term Notes Series M, due September 2023.

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. Long Island Electric Utility Servco, LLC (Servco) does not participate in the corporate money pool. Servco’s short-term liquidity needs are met through an account funded and owned by LIPA.

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

NDT Fund Obligation

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 NDT reporting period. The current market downturn associated with inflation and rising interest rates is not currently expected to result in any supplemental required funding of the NDT Fund. To the extent of a prolonged economic downturn, our funding requirements may increase in future periods to meet NRC minimum funding requirements.

Common Stock Dividends

On July 19, 2022, PSEG’s Board of Directors approved a $0.54 per share common stock dividend for the third quarter of 2022. This reflects an indicative annual dividend rate of $2.16 per share. We expect to continue to pay cash dividends on our common stock; however, the declaration and payment of future dividends to holders of our common stock will be at the discretion of the Board of Directors and will depend upon many factors, including our financial condition, earnings, capital requirements of our businesses, alternate investment opportunities, legal requirements, regulatory constraints, industry practice and other factors that the Board of Directors deems relevant. For additional information related to cash dividends on our common stock, see Item 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. 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

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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 2021 Form 10-K.

PSE&G

During the nine months ended September 30, 2022, PSE&G made capital expenditures of $1,871 million, primarily for T&D system reliability. This does not include expenditures for energy efficiency and electric vehicle programs of approximately $191 million and cost of removal, net of salvage, of $94 million, which are included in operating cash flows.

Other

During the nine months ended September 30, 2022, PSEG made capital expenditures of $77 million, excluding $140 million for nuclear fuel, primarily related to various nuclear projects.

ACCOUNTING MATTERS

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

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