PUBLIC SERVICE ENTERPRISE GROUP, INC. This combined MD&A is separately filed by
PSEG's business consists of two reportable segments,
•PSE&G-which is a public utility engaged principally in the transmission of electricity and distribution of electricity and natural gas in certain areas ofNew Jersey . PSE&G is subject to regulation by theNew Jersey Board of Public Utilities (BPU) and theFederal Energy Regulatory Commission (FERC). PSE&G also invests in regulated solar generation projects and energy efficiency and related programs inNew 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 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 byFERC , theNuclear Regulatory Commission (NRC), theEnvironmental Protection Agency (EPA ) and the states in which they operate.PSEG Power is no longer aSecurities and Exchange Commission (SEC) registrant; however, it continues to be consolidated and reported in PSEG's financial statements as a wholly owned subsidiary and operating segment. InAugust 2021 , PSEG entered into two agreements to sellPSEG Power's 6,750 megawatts (MW) fossil generating portfolio to newly formed subsidiaries ofArcLight Energy Partners Fund VII, L.P. , a fund controlled byArcLight Capital Partners, LLC . InFebruary 2022 , we completed the sale of this fossil generating portfolio. As a result, disclosures in this Item 7 and elsewhere in this document that relate solely to this 6,750 MW fossil generating portfolio, except for those related to certain assets and liabilities excluded from the sale transactions, primarily for obligations under environmental regulations, including possible remediation obligations under the New Jersey Industrial Site Recovery Act and the Connecticut Transfer Act, are no longer relevant to our business. 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 portfolio of lease investments;PSEG Long Island LLC (PSEG LI), which operates theLong Island Power Authority's (LIPA) transmission and distribution (T&D) system under an Operations Services Agreement (OSA); andPSEG Services Corporation (Services), which provides certain management, administrative and general services to PSEG and its subsidiaries at cost. Our business discussion in Item 1. Business provides a review of the regions and markets where we operate and compete, as well as our strategy for conducting our businesses within these markets, focusing on operational excellence, financial strength and making disciplined investments. Our risk factor discussion in Item 1A. Risk Factors provides information about factors that could have a material adverse impact on our businesses. The following discussion provides an overview of the significant events and business developments that have occurred during 2021 and key factors that we expect may drive our future performance. This discussion refers to the Consolidated Financial Statements (Statements) and the related Notes to the Consolidated Financial Statements (Notes). This discussion should be read in conjunction with such Statements and Notes. For a discussion of 2020 items and year-over-year comparisons of changes in our financial condition and results of operations as of and for the years endedDecember 31, 2020 andDecember 31, 2019 , see Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations in our Annual Report on Form 10-K for the year endedDecember 31, 2020 (2020 Annual Report) as filed with theSEC onFebruary 26, 2021 .
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 energy 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 and 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
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the sustainability and predictability of our earnings and cash flows. InJune 2021 , we completed the sale ofPSEG Power's solar portfolio and inAugust 2021 we entered into two agreements to sellPSEG Power's 6,750 MW of fossil generation located inNew Jersey ,Connecticut ,New York andMaryland . InFebruary 2022 , we completed the sale of this fossil generation portfolio, 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. See Item 8. 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 customer bad debts and lower cash collections, as discussed below. 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 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 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 6.5% 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 filed inNovember 2021 . The IAP is a proposed$848 million investment program 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. During 2022, we expect to file for extensions of our GSMP and CEF-EE program, which we expect will conclude in the first half of 2023. InSeptember 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 provides for recovery of lost electric and gas variable margin revenues relative to a baseline of the test year (July 2017 toJune 2018 ) set in in our last base rate case. The deferral period for this mechanism became effective inJune 2021 for electric andOctober 2021 for gas. PSE&G suspended its gas Weather Normalization Charge (WNC) when the gas CIP began. InJanuary 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 is driven by the implementation of advanced metering infrastructure (AMI), is estimated to be$707 million , invested over the next four years. Also inJanuary 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 approximately$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 was the subject of a stakeholder process at the BPU in 2021. We currently anticipate that this effort will conclude with PSE&G submitting a filing in mid-year 2022 targeting infrastructure investments for the medium and heavy duty EV market. 40 --------------------------------------------------------------------------------
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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 to be filed with the BPU by the end of 2023. 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 the second half of 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. As part of a solicitation by the BPU, we also proposed two transmission projects to support the development of offshore wind which are being evaluated by theBPU andPJM Interconnection, L.L.C. (PJM), with project awards expected in late 2022. As discussed further below, inOctober 2021 ,FERC approved PSE&G's settlement with the BPU and theNew 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%. Under currentFERC rules, we continue to earn a 50 basis point adder to that base ROE for our membership in PJM.
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. TheState of New Jersey issued an Executive Order inMarch 2020 that included a moratorium on non-safety related service disconnections for non-payment. OnJune 30, 2021 , the moratorium imposed by theState of New Jersey ended but the State had established a "grace period" prohibiting disconnections for residential customers throughDecember 31, 2021 . OnJanuary 22, 2022 , the State extended the grace period toMarch 15, 2022 . Consequently, collections and shut-offs will not be in full effect untilmid-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. Since the start of the pandemic, PSE&G's allowance for credit losses has increased by approximately$265 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. Collection efforts with C&I customers recommenced in the fourth quarter of 2021 and residential customer collection efforts will recommence inMarch 2022 , with a focus on enrolling customers in payment support programs. Any further moratoriums on shut-offs or collection processes could have a material effect on our cash flows, and, to the extent not fully recovered through a rate-making process, on our financial results and condition. InJuly 2020 , the BPU authorized regulated utilities inNew Jersey , including PSE&G, to create a COVID-19-related Regulatory Asset by deferring on their books and records prudently incurred incremental costs related to COVID-19 beginning onMarch 9, 2020 throughSeptember 30, 2021 for recovery in a future rate case. InSeptember 2021 , the BPU extended the authorization to defer such costs throughDecember 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 ofDecember 31, 2021 , PSE&G has recorded a Regulatory Asset related to COVID-19 to defer incremental costs of$116 million , which PSEG believes are recoverable under the BPU Order.
InJuly 2020 , we announced that we were exploring strategic alternatives forPSEG 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. See Item 8. Note 4. Early Plant Retirements/Asset Dispositions and Impairments for additional information. InMay 2021 ,PSEG Power Ventures LLC (Power Ventures ), a direct wholly owned subsidiary ofPSEG Power , entered into a purchase agreement withQuattro Solar, LLC , an affiliate ofLS Power , relating to the sale byPower Ventures of 100% of its ownership interest inPSEG Solar Source LLC (Solar Source) including its related assets and liabilities. The transaction closed inJune 2021 .
In
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February 2022 , PSEG completed the sale of this fossil generating portfolio. These transformative transactions are expected to 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 the transition to carbon-free generation. See Item 8. Note 4. Early Plant Retirements/Asset Dispositions and Impairments for additional information. We have sought to achieve operational excellence and manage costs in order to optimize cash flow generation from our fleet in light of low wholesale power and gas prices, environmental considerations and competitive market forces that reward efficiency and reliability. During 2021, our natural gas and nuclear units generated 22.5 and 31.2 terawatt hours and operated at a capacity factor of 49.1% and 91.9%, respectively.PSEG Power's hedging practices help to manage some of the volatility of the merchant power business. More than 90% ofPSEG Power's expected gross margin in 2022 from the expected remaining generation assets after the sale of the fossil generation portfolio relates to hedging of our energy margin, our expected revenues from the capacity market mechanisms, 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. As a result of significantly rising energy prices, as experienced during the second half of 2021,PSEG Power experienced a substantial increase in net cash collateral postings related to hedge positions that are out-of-the-money. As ofDecember 31, 2021 , net cash collateral postings were$844 million . As discussed further below under "Wholesale Power Market Design," inJuly 2021 , PJM submitted toFERC a proposal to replace the current MinimumOffer 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 MOPR. PJM's proposal requested thatFERC approve the new provisions for the next Reliability Pricing Model (RPM) auction. InSeptember 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 ofSeptember 29, 2021 and will apply to the next base residual auction. In February,FERC approved PJM's filing requesting that the auction be held inJune 2022 .
PSEG LI
Following the effects of Tropical Storm Isaias, theNew York Attorney General (AG) initiated an inquiry into PSEG LI's preparation and response to the storm. In addition, theDepartment of Public Service (DPS) within theNew 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. InDecember 2020 , LIPA filed a complaint against PSEG LI inNew 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. InJune 2021 , LIPA and PSEG LI executed a non-binding term sheet, which 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. An amended OSA based on the term sheet was agreed to by the parties and approved by the LIPA Board inDecember 2021 . InJanuary 2022 , theNew York AG approved the Amended OSA and it has been submitted to the New York Comptroller for approval, which approval must occur byApril 1, 2022 (such date is subject to amendment by mutual agreement of PSEG LI and LIPA) in order for the Amended OSA to become binding and effective. Such approval would result in retroactive effectiveness toJanuary 1, 2022 for purposes of compensation. The OSA contract term will continue through 2025, with a mutual option to extend for five years. No assurances can be given regarding obtaining the New York Comptroller approval and the closing of the inquiry by the AG. In the event that the Amended OSA is not approved by the New York Comptroller byApril 1, 2022 , 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 safe, more reliable and more resilient. InJune 2021 , we accelerated and expanded our net zero vision by 20 years, establishing 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) at bothPSEG Power and PSE&G (covering our electric and 42 --------------------------------------------------------------------------------
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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. InSeptember 2021 , we also committed to theUnited Nations -backed Race to Zero campaign. We have agreed to develop and submit science-based emission reduction targets following the criteria and recommendations of the Science Based Targets Initiative bySeptember 2023 . Targets will encompass Scopes 1, 2, and 3 (which includes downstream/customer use of energy products as well as purchased goods and services for our own operations) and must be in line with 1.5oC emissions scenarios. 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 recently approved CEF-EE, CEF-EC and CEF-EV programs and the proposed CEF-ES program are intended to supportNew 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 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 delivery of natural gas to almost two million customers throughoutNew 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, later in 2022 we will file 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. These investments have proven effective in recent severe weather events, including Tropical Storm Ida inAugust 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 inNew Jersey , by advocating for state and federal policies that recognize the value of emission-free generation and reduce 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 theNew Jersey electric system.
Offshore Wind
InDecember 2020 , PSEG entered into a definitive agreement with ØrstedNorth America Inc. (Ørsted) to acquire a 25% equity interest in Ørsted'sOcean Wind project which is currently in development.Ocean Wind was selected byNew 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. OnMarch 31, 2021 , the BPU approved PSEG's investment inOcean Wind and the acquisition was completed inApril 2021 . Additionally, PSEG and Ørsted each owns 50% ofGarden State Offshore Energy LLC (GSOE) which holds rights to an offshore wind lease area just south ofNew Jersey . InDecember 2021 , theMaryland Public Service Commission awarded Ørsted's 846 MW Skipjack 2 project Offshore Renewable Energy Credits underMaryland'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 expects to determine whether to exercise this option during 2022. PSEG and Ørsted are also exploring further opportunities to develop the remaining GSOE lease area. InApril 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 supportNew Jersey's planned offshore wind generation. The state agreement approach requires customers in the requesting state - in this caseNew Jersey - to pay for the costs of these public policy transmission projects. InSeptember 2021 , PSEG and Ørsted 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. 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 excellence in operational performance while developing opportunities in both our regulated and competitive businesses. In 2021, our utility continued its efforts to control costs while maintaining strong operational performance.
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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 2021 as we
•maintained sufficient liquidity,
•completed the sale of
•maintained solid investment grade credit ratings, and
•increased our annual dividend for 2021 to
In lateSeptember 2021 , we announced a$500 million share repurchase program to be implemented upon the close of the sale of the fossil generating assets. InNovember 2021 , our Board of Directors authorized senior management to implement a share repurchase program at such time as senior management deemed appropriate in its discretion, whether before or after the closing of the sale of the fossil generating assets. InDecember 2021 , under this authorization, we entered into an open market share repurchase plan for$250 million of our common shares. There were no common share repurchases during the fourth quarter of 2021. During January and throughFebruary 16, 2022 , we purchased the full$250 million of common shares under the open market share repurchase plan. 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. In conjunction with the announced sale of our Fossil business, inOctober 2021 we redeemed all ofPSEG Power's remaining debt. see Item 8. Note 16. Debt and Credit Facilities for additional details.
Financial Results
The financial results for PSEG,
Years Ended December 31,
2021 2020
Millions, except per share data
PSE&G $ 1,446 $ 1,327
PSEG Power (2,056) 594
Other (38) (16)
PSEG Net Income (Loss) $ (648) $ 1,905
PSEG Net Income (Loss) Per Share (Diluted) $ (1.29) $ 3.76
Our 2021 Net Loss as compared to our 2020 Net Income was due to an impairment
loss and related charges associated with the sale of PSEG Power's fossil
generation assets. For a more detailed discussion of our financial results, see
Results of Operations.
The greater emphasis on capital spending in recent years for projects at PSE&G
relative to PSEG Power , particularly those on which we receive contemporaneous
returns at PSE&G has yielded strong results, which has allowed us to meet
customer needs and address market conditions and investor expectations. We
continue our focus on operational excellence, financial strength and disciplined
investment. These guiding principles have provided the base from which we have
been able to execute our strategic initiatives.
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 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, and
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•continued to evaluate potential additional offshore wind opportunities, including submitting a number of proposals in response to an offshore transmission solicitation.
Regulatory, Legislative and Other Developments
In our pursuit of operational excellence, financial strength and disciplined investment, we closely monitor and engage with stakeholders on significant regulatory and legislative developments. Transmission planning rules and wholesale power market design are of particular importance to our results and we continue to advocate for policies and rules that promote fair and efficient electricity markets. For additional information about regulatory, legislative and other developments that may affect us, see Item 1. Business-Regulatory Issues.
Transmission Rate Proceedings and ROE
InMarch 2019 ,FERC issued a Notice of Inquiry seeking comments on improvements toFERC's electric transmission incentives policy. Subsequently, inApril 2021 ,FERC issued a supplemental notice of proposed rulemaking to eliminate the incentive forRegional 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-$40 million . InOctober 2021 ,FERC approved a settlement agreement effectiveAugust 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% 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 inJanuary 2022 .
Wholesale Power Market Design
InJuly 2021 , PJM submitted toFERC a proposal to replace the extended MOPR 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. InSeptember 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 ofSeptember 29, 2021 and will apply to the next base residual auction, which has been delayed. In February,FERC approved PJM's filing requesting that the auction be held inJune 2022 . InNovember 2021 , a group of generators challenged the new MOPR rules in theCourt of Appeals for the Third Circuit on the grounds thatFERC's inaction was unlawful. PSEG has intervened in the proceeding in support of the new MOPR rules. We cannot predict the outcome of this proceeding. In another order related to the auction,FERC found that the current rules related to the Market SellerOffer 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. InJuly 2021 , the BPU issued a report on its investigation related to whetherNew 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 forNew 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 thatNew Jersey continue to explore aNew Jersey -only or regional competitive auction design if potential reforms at the regional and national level are not sufficient to allowNew 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. InJanuary 2020 ,New Jersey rejoined the Regional Greenhouse Gas Initiative (RGGI). As a result, generating plants operating inNew Jersey , including those owned byPSEG Power , that emit carbon dioxide emissions will be required to procure credits for each ton they emit. Following the close on the sale of the fossil generating assets, we no longer have generation subject to the RGGI compliance requirements.
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 thePassaic and Hackensack Rivers are alleged by Federal and State agencies to have discharged substantial contamination into thePassaic River/Newark Bay Complex in violation of various statutes. In addition,PSEG Power will retain ownership of certain assets and liabilities 45 --------------------------------------------------------------------------------
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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 8. Note 15. Commitments and Contingent Liabilities.
Nuclear
InApril 2019 ,PSEG Power's Salem 1,Salem 2 andHope 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, throughMay 2022 . InApril 2021 ,PSEG Power's Salem 1,Salem 2 andHope Creek nuclear plants were awarded ZECs for the three-year eligibility period startingJune 2022 at the same approximate$10 per MWh received during the current ZEC period throughMay 2022 referenced above. As a result, each nuclear plant is expected to receive ZEC revenue for an additional three years startingJune 2022 . The terms and conditions of thisApril 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 ourNew 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 fromNew 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. InMay 2021 , the New Jersey Rate Counsel filed an appeal with theNew Jersey Appellate Division of the BPU's April 2021 decision. PSEG cannot predict the outcome of this matter. In the event that (i) the ZEC program is overturned or is otherwise materially adversely modified through legal process; or (ii) any of theSalem 1,Salem 2 andHope 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 revenues provided under a program approved by the BPU in accordance with aFERC -authorized capacity mechanism), or, in the case of theSalem nuclear plants, decisions by theEPA 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 onPSEG's andPSEG Power's results of operations.
Tax Legislation
A prolonged coronavirus 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 Consolidated Appropriations Act, 2021, enacted in lateDecember 2020 , provides a 30% investment tax credit (ITC) for offshore wind projects that begin construction beforeDecember 31, 2025 . In addition, onDecember 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. InJuly 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 46 --------------------------------------------------------------------------------
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of
InMarch 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 afterDecember 31, 2017 and beforeJanuary 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 theIRS and theJoint 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 withNew 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 valueNew 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,
•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.
In addition to the risks described elsewhere in this Form 10-K for 2021 and beyond, the key issues and challenges we expect our business to confront include:
•regulatory and political uncertainty, both with regard to future energy policy, design of energy and capacity markets, transmission policy and environmental regulation, as well as with respect to the outcome of any legal, regulatory or other proceedings, •the continuing impact of the ongoing coronavirus pandemic and the associated regulations and economic impacts, which could extend beyond the duration of the pandemic,
•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; 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, •the further disposition or restructuring of our merchant generation business or portions thereof beyond the aforementioned sale ofPSEG Power's fossil and solar generating assets or other existing businesses or the acquisition or development of new businesses, 47 --------------------------------------------------------------------------------
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•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 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.
RESULTS OF OPERATIONS
Years Ended December 31,
2021 2020 2019
Earnings (Losses) Millions
PSE&G $ 1,446 $ 1,327 $ 1,250
PSEG Power (A) (2,056) 594 468
Other (B) (38) (16) (25)
PSEG Net Income (Loss) $ (648)
PSEG Net Income (Loss) Per Share (Diluted)
(A)PSEG Power's results in 2021 include an after-tax impairment loss and other associated charges, including debt extinguishment costs, of$2,158 million related to the sale ofPSEG Power's fossil generation assets.PSEG Power's results in 2020 include an after-tax gain of$86 million related to the sale of its ownership interest in theYards Creek generation facility.PSEG Power's results in 2019 include an after-tax loss of$286 million related to the sale of its ownership interests in the Keystone and Conemaugh fossil generation plants. See Item 8. Note 4. Early Plant Retirements/Asset Dispositions and Impairments for additional information.
(B)Other includes after-tax activities at the parent company,
PSEG Power's results above include theNuclear 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
Years Ended December 31,
2021 2020 2019
Millions, after tax
NDT Fund and Related Activity (A) (B) $ 108 $ 137 $ 152
Non-Trading MTM Gains (Losses) (C) $ (446) $ (58) $ 205
(A)NDT Fund Income (Expense) includes gains and losses on NDT securities which
are recorded in Net Gains (Losses) on Trust Investments. See Item 8. Note 11.
Trust Investments for additional information. NDT Fund Income (Expense) also
includes interest and dividend income and other costs related to the NDT Fund
recorded in Other Income (Deductions), interest accretion expense on PSEG
Power's nuclear Asset Retirement Obligation (ARO) recorded in Operation &
Maintenance (O&M) Expense and the depreciation related to the ARO asset recorded
in Depreciation and Amortization (D&A) Expense.
(B)Net of tax (expense) benefit of
(C)Net of tax (expense) benefit of
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The Net Loss in 2021 as compared to Net Income in 2020 was driven primarily by
•an impairment loss and related charges taken as a result of the sale of the
fossil generation assets at
•higher MTM losses at
•a gain on the sale of
•partially offset by higher earnings due to continued investments in T&D programs at PSE&G, and
•higher pension and OPEB credits.
Our results of operations are primarily comprised of the results of operations of our principal operating segments,PSE&G andPSEG Power , excluding charges related to intercompany transactions, which are eliminated in consolidation. For additional information on intercompany transactions, see Item 8. Note 26. Related-Party Transactions. Increase / Increase / Years Ended December 31, (Decrease) (Decrease) 2021 2020 2019 2021 vs. 2020 2020 vs. 2019 Millions Millions % Millions % Operating Revenues$ 9,722 $ 9,603 $ 10,076 $ 119 1 $ (473) (5) Energy Costs 3,499 3,056 3,372 443 14 (316) (9)
Operation and Maintenance 3,226 3,115 3,111 111 4 4 -
Depreciation and Amortization 1,216 1,285 1,248 (69) (5) 37 3
(Gains) Losses on Asset
Dispositions and Impairments 2,637 (123) 402 2,760 N/A (525) N/A
Income from Equity Method
Investments 16 14 14 2 14 - -
Investments 194 253 260 (59) (23) (7) (3)
Other Income (Deductions) 98 115 125 (17) (15) (10) (8)
Non-Operating Pension and OPEB
Credits (Costs) 328 249 177 79 32 72 41
Loss on Extinguishment of Debt (298) -
- (298) N/A - N/A
Interest Expense 571 600 569 (29) (5) 31 5
Income Tax (Benefit) Expense (441) 396 257 (837) N/A 139 54
The 2021, 2020 and 2019 amounts in the preceding table for Operating Revenues
and O&M costs each include $511 million , $520 million and $490 million ,
respectively, for PSEG LI's subsidiary, Long Island Electric Utility Servco, LLC
(Servco). These amounts represent the O&M pass-through costs for the Long Island
operations, the full reimbursement of which is reflected in Operating Revenues.
See Item 8. Note 5. Variable Interest Entities for additional information. The
following discussions for PSE&G and PSEG Power provide a detailed explanation of
their respective variances.
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PSE&G
Increase / Increase /
Years Ended December 31, (Decrease) (Decrease)
2021 2020 2019 2021 vs. 2020 2020 vs. 2019
Millions Millions % Millions %
Operating Revenues $ 7,122 $ 6,608 $ 6,625 $ 514 8 $ (17) -
Energy Costs 2,688 2,469 2,738 219 9 (269) (10)
Operation and Maintenance 1,692 1,614 1,581 78 5 33 2
Depreciation and Amortization 928 887 837 41 5 50 6
Gain on Asset Dispositions (4) (1) - (3) N/A (1) N/A
Net Gains (Losses) on Trust
Investments 2 3 2 (1) (33) 1 50
Other Income (Deductions) 88 108 83 (20) (19) 25 30
Non-Operating Pension and OPEB
Credits (Costs) 264 205 150 59 29 55 37
Interest Expense 402 388 361 14 4 27 7
Income Tax Expense 324 240 93 84 35 147 N/A
Year Ended
Operating Revenues increased
Delivery Revenues increased
•Transmission revenues increased$113 million due to higher revenue requirements calculated through our transmission formula rate, primarily to recover required investments. The net increase in 2021 includes a reduction to the revenue requirement of approximately$64 million as a result of our ROE settlement approved byFERC effectiveAugust 1, 2021 , partially offset by a$35 million flowback of certain excess deferred income taxes in 2020. The$35 million flowback was offset in Income Tax Expense in 2020. •Gas distribution revenues increased$65 million due to increases of$42 million from collection of the GSMP in base rates,$18 million in CIP decoupling revenues,$7 million in collections of Green Program Recovery Charges (GPRC) and$7 million from higher sales volumes. These increases were partially offset by a decrease of$9 million in WNC revenues. •Electric distribution revenues increased$59 million due primarily to$30 million from CIP decoupling revenue,$13 million in higher collections of GPRC,$9 million from an Energy Strong II rate roll-in and$7 million from higher sales volumes.
•Electric distribution and gas distribution revenue requirements were
Clause Revenues increased$47 million due to$17 million in Tax Adjustment Credits (TAC) and GPRC deferrals,$28 million in higher Societal Benefits Charges (SBC) and$4 million in Margin Adjustment Clause (MAC) revenues. These increases were partially offset by$2 million in lower Solar Pilot Recovery Charge (SPRC) collections. The changes in TAC and GPRC Deferrals, SBC, MAC and SPRC collections were entirely offset by the amortization of related costs (Regulatory Assets) in O&M, D&A and Interest and Tax Expenses. PSE&G does not earn margin on TAC or GPRC deferrals or on SBC, MAC or SPRC collections. Commodity Revenues increased$217 million due to higher Gas revenues and Electric revenues. The changes in Commodity Revenues for both gas and electric are entirely offset by changes in Energy Costs. PSE&G earns no margin on the provision of basic gas supply service (BGSS) and BGS to retail customers.
•Gas revenues increased
•Electric revenues increased
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Other Operating Revenues increased$29 million due to a$27 million increase primarily in appliance service revenues and a$25 million increase from the sale of Transition Renewable Energy Certificates (TREC). These increases were partially offset by a$20 million reduction in revenues from Solar Renewable Energy Credits (SREC) and a$3 million reduction in ZEC revenues. The changes in TREC, SREC and ZEC revenues are entirely offset by changes to Energy Costs.
Operating Expenses
Energy Costs increased
Operation and Maintenance increased
Depreciation and Amortization increased$41 million due primarily to an increase in depreciation of$55 million due to additional plant placed into service and a$6 million increase from the amortization of software. These increases were partially offset by a$19 million decrease due to lower transmission depreciation rates effectiveAugust 1, 2021 , which were included in the settlement of the formula rate and other matters. Other Income (Deductions) decreased$20 million due primarily to a decrease of$16 million in the Allowance forFunds Used During Construction (AFUDC) from lower transmission expenditures and a$4 million net decrease in solar loan interest and miscellaneous other income.
Non-Operating Pension and OPEB Credits (Costs) increased
Interest Expense increased
Income Tax Expense increased$84 million due primarily to higher pre-tax income in 2021 and reduced flowback of excess deferred income tax liabilities in 2021, partially offset by the tax benefit from the CEF program investments.
Year Ended
See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations in our 2020 Annual Report.
PSEG Power Increase / Increase / Years Ended December 31, (Decrease) (Decrease) 2021 2020 2019 2021 vs. 2020 2020 vs. 2019 Millions Millions % Millions %
Operating Revenues $ 3,147 $ 3,634 $ 4,385 $ (487) (13) $ (751) (17)
Energy Costs 1,978 1,821 2,118 157 9 (297) (14)
Operation and Maintenance 983 964 1,040 19 2 (76) (7)
Depreciation and Amortization 256 368 377 (112) (30) (9) (2)
(Gains) Losses on Asset
Dispositions and Impairments 2,641 (122) 402 2,763 N/A (524) N/A
Income from Equity Method
Investments 16 14 14 2 14 - -
Net Gains (Losses) on Trust
Investments 187 241 253 (54) (22) (12) (5)
Other Income (Deductions) 29 12 54 17 N/A (42) N/A
Non-Operating Pension and OPEB
Credits (Costs) 47 33 21 14 42 12 57
Loss on Extinguishment of Debt (298) - - (298) N/A - N/A
Interest Expense 78 121 119 (43) (36) 2 2
Income Tax Expense (Benefit) (752) 188 203 (940) N/A (15) (7)
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Year Ended
Operating Revenues decreased
Generation Revenues decreased
•a net decrease of$606 million due to higher MTM losses in 2021 as compared to 2020. Of this amount, there was a$624 million decrease due to changes in forward prices, partially offset by an$18 million increase due to less losses on positions reclassified to realized upon settlement in 2021, •a net decrease of$288 million due primarily to$201 million from lower volumes of electricity sold under the BGS contracts, coupled with an$87 million impact from the transfer of responsibility for firm transmission services from BGS suppliers to the Electric Distribution Companies (EDCs), and
•a net decrease of
•partially offset by a net increase of$188 million due primarily to higher average realized prices and higher volumes sold in the PJM,New England (NE) andNew York (NY) regions, and •a net increase of$64 million in capacity revenues due primarily to increases in auction prices, coupled with decreases in capacity charges due to lower BGS and other load obligations in the PJM region, partially offset by lower capacity prices and the retirement of theBridgeport Harbor 3 (BH3) coal plant in the NE region.
Gas Supply Revenues increased
•a net increase of
•a net increase of$74 million related to sales to third parties, of which$90 million was due to higher average sales prices, partially offset by$16 million due to lower volumes sold. 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 meetPSEG Power's obligation under its BGSS contract with PSE&G. Energy Costs increased$157 million due to Generation costs decreased$13 million due primarily to •a net decrease of$147 million in transmission costs due primarily to an$87 million impact from the transfer of responsibility for firm transmission services under BGS contracts from BGS suppliers to the EDCs, coupled with a$60 million decrease in other transmission costs, mainly from lower volumes of electricity sold under the BGS contracts, and •a net decrease of$66 million due to higher net MTM gains in 2021. Of this amount, there was a$52 million decrease due to changes in forward prices, coupled with a$14 million decrease due to more gains on positions reclassified to realized upon settlement in 2021,
•partially offset by a net increase of
•a net increase of$42 million in energy purchases due primarily to an increase in purchased volumes in the PJM region to meet physical energy sales. This was partially offset by a decrease in renewable energy credit requirements caused by decreases in load served in the PJM region.
Gas costs increased
•a net increase of$103 million in costs related to sales under the BGSS contract, of which$74 million was due to the higher average cost of gas and$29 million to higher send out volumes. 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, and •a net increase of$67 million related to sales to third parties, of which$81 million was due to an increase in the average cost of gas, partially offset by a decrease of$14 million due to lower volumes sold. Operation and Maintenance increased$19 million due primarily to a refueling outage in 2021 at our 100%-ownedHope Creek nuclear plant as compared to an outage in 2020 at our 57%-ownedSalem 2 nuclear plant and severance costs related to the sale of the fossil generating plants, partially offset by lower costs in 2021 due to the sale of our ownership interest in the solar plants inJune 2021 . 52 --------------------------------------------------------------------------------
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Depreciation and Amortization decreased
(Gains) Losses on Asset Dispositions and Impairments. The loss in 2021 primarily reflects a$2,691 million impairment due to the sale of the fossil generating plants and other impairments, partially offset by a$63 million gain from the sale of the solar plants. The$122 million gain in 2020 was due to the sale of our ownership interest in theYards Creek generation facility. See Item 8. Note 4. Early Plant Retirements/Asset Dispositions and Impairments.Net Gains (Losses) on Trust Investments decreased$54 million due primarily to a$101 million decrease in net unrealized gains on equity investments in theNDT Fund , partially offset by a$46 million increase in net realized gains onNDT Fund investments. Other Income (Deductions) increased$17 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 onNDT Fund investments in 2021. Non-Operating Pension and OPEB Credits (Costs) increased$14 million due to a decrease in interest cost and an increase in the expected return on plan assets, partially offset by an increase in the amortization of net prior service cost. Loss on Extinguishment of Debt represents a loss incurred in 2021 for a make whole premium that was payable upon early redemption of all outstanding debt obligations and other non-cash debt extinguishment costs.
Interest Expense decreased
Income Tax Expense decreased$940 million due primarily to lower pre-tax income in 2021, partially offset by the recapture of ITCs related to the sale of the solar plants in 2021, 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, and the purchase of less New Jersey NOL tax benefits in 2021.
Year Ended
See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations in our 2019 Annual Report.
LIQUIDITY AND CAPITAL RESOURCES
The following discussion of our liquidity and capital resources is on a consolidated basis, noting the uses and contributions, where material, of our two direct major operating subsidiaries.
Financing Methodology
We expect our capital requirements to be met through internally generated cash flows and external financings, consisting of short-term debt for working capital needs and long-term debt for capital investments. PSE&G's sources of external liquidity include a$600 million multi-year revolving credit facility. PSE&G uses internally generated cash flow and its commercial paper program to meet seasonal, intra-month and temporary working capital needs. PSE&G does not engage in any intercompany borrowing or lending arrangements. PSE&G maintains back-up facilities in an amount sufficient to cover the commercial paper and letters of credit outstanding. PSE&G's dividend payments to/capital contributions from PSEG are consistent with its capital structure objectives which have been established to maintain investment grade credit ratings. PSE&G's long-term financing plan is designed to replace maturities, fund a portion of its capital program and manage short-term debt balances. Generally, PSE&G uses either secured medium-term notes or first mortgage bonds to raise long-term capital.
PSEG,
PSEG's available sources of external liquidity may include the issuance of long-term debt securities and the incurrence of additional indebtedness under credit facilities. Our current sources of external liquidity include multi-year revolving credit facilities totaling$1.5 billion . These facilities are available to back-stop PSEG's commercial paper program, issue letters of credit and for general corporate purposes. PSEG's credit facilities and the commercial paper program are available to support PSEG's working capital needs and are also available to make equity contributions or provide liquidity support to its subsidiaries. Additionally, from time to time, PSEG enters into short-term loan agreements designed to enhance its liquidity position.
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market prices for energy and fuel fluctuate, and to meet potential collateral postings in the event thatPSEG Power is downgraded to below investment grade byStandard & Poor's (S&P) or Moody's.PSEG Power's dividend payments to PSEG are also designed to be consistent with its capital structure objectives which have been established to maintain investment grade credit ratings and provide sufficient financial flexibility.
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 year endedDecember 31, 2021 , our operating cash flow decreased$1,366 million . The net decrease was primarily due to a$780 million reduction related to net cash collateral posting requirements atPSEG Power and a net change at PSE&G, as discussed below. In addition, in 2021, there were higher tax payments atPSEG Power and lower tax refunds at the parent company, partially offset by lower tax payments atEnergy 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$229 million from$1,953 million to$1,724 million for the year endedDecember 31, 2021 , as compared to 2020, due primarily to a net increase in regulatory deferrals, increases in electric energy and vendor payments, and higher tax payments in 2021, partially offset by higher earnings. Short-Term Liquidity
PSEG meets its short-term liquidity requirements, as well as those of
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 second half 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$844 million at the end of December. PSEG issued short-term borrowings, including commercial paper, in order to satisfy the increase in collateral postings and to prepare for thePSEG Power debt redemption. In October,PSEG Power borrowed$755 million from its credit facility to support its Senior Notes redemption and additional cash collateral postings, as needed. In November, PSEG issued$1.5 billion of Senior Notes, using a portion of the funds to provide support toPSEG Power for paying off the$755 million loan from the credit facility. InMarch 2020 , PSEG entered into a$300 million , 364-day term loan agreement which was prepaid inJanuary 2021 . In March andMay 2021 , PSEG entered into two 364-day variable rate term loan agreements for$500 million and$750 million , respectively. InAugust 2021 , PSEG entered into a$1.25 billion , 364-day variable rate term loan agreement. These term loans are not included in the credit facility amounts presented in the following table. Our total credit facilities and available liquidity as ofDecember 31, 2021 were as follows: As of December 31, 2021 Total Available Company/Facility Facility Usage Liquidity Millions PSEG$ 1,500 $ 1,022 $ 478 PSE&G 600 18 582 PSEG Power 2,000 145 1,855 Total$ 4,100 $ 1,185 $ 2,915
For additional information, see Item 8. Note 16. Debt and Credit Facilities.
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As ofDecember 31, 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 ofPSEG 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 ofPSEG Power's credit rating, certain ofPSEG 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 ifPSEG Power were to lose its investment grade credit rating was approximately$1,151 million and$840 million as ofDecember 31, 2021 and 2020, respectively. See Item 8. Note 15. Commitments and Contingent Liabilities for additional discussion ofPSEG Power's agreements.
Long-Term Debt Financing
During the fourth quarter of 2021 PSEG:
•issued
•issued
•retired
InOctober 2021 , PSEG redeemed all remaining outstanding Senior Notes ofPSEG Power due to covenants that could trigger a default from the sale ofPSEG Power's fossil generating plants. This included$700 million of 3.85% Senior Notes due to mature inJune 2023 ,$250 million of 4.30% Senior Notes due to mature inNovember 2023 , and$404 million of 8.63% Senior Notes due to mature inApril 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 underPSEG Power's credit facility. In addition, approximately$4 million of other non-cash debt extinguishment costs related to the redemption were recorded inOctober 2021 .
During the next twelve months,
•PSEG has
For additional information, see Item 8. Note 16. Debt and Credit Facilities.
Debt Covenants
Our credit agreements contain maximum debt to equity ratios and other restrictive covenants and conditions to borrowing. We are currently in compliance with all of our debt covenants. Continued compliance with applicable financial covenants will depend upon our future financial position, level of earnings and cash flows, as to which no assurances can be given. In addition, under its First and Refunding Mortgage (Mortgage), PSE&G may issue new First and Refunding Mortgage Bonds against previous additions and improvements, provided that its ratio of earnings to fixed charges calculated in accordance with its Mortgage is at least 2 to 1, and/or against retired Mortgage Bonds. As ofDecember 31, 2021 , PSE&G's Mortgage coverage ratio was 4.7 to 1 and the Mortgage would permit up to approximately$8.4 billion aggregate principal amount of new Mortgage Bonds to be issued against additions and improvements to its property. Default Provisions Our bank credit agreements and indentures contain various, customary default provisions that could result in the potential acceleration of indebtedness under the defaulting company's agreement. In particular, PSEG's bank credit agreements contain provisions under which certain events, including an acceleration of material indebtedness underPSE&G's andPSEG Power's respective financing agreements, a failure by PSE&G orPSEG Power to satisfy certain final judgments and certain bankruptcy events by PSE&G orPSEG Power , would constitute an event of default under the PSEG bank credit agreements. Under the PSEG bank credit agreements, it would also be an event of default if either PSE&G orPSEG Power ceases to be wholly owned by PSEG.The PSE&G andPSEG Power bank credit agreements include similar default provisions; however, such provisions only relate to the respective borrower under such agreement and its subsidiaries and do not contain cross default provisions to each other.The PSE&G andPSEG Power bank credit agreements do not include cross default provisions relating to PSEG.PSEG Power's bank credit agreements also contain limitations on the incurrence of subsidiary debt and liens.
There are no cross-acceleration provisions in PSEG's or PSE&G's indentures.
However, PSEG's existing notes include a cross acceleration provision that may
be triggered upon the acceleration of more than
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InMarch 2021 , each ofPSEG andPSEG Power and its subsidiaries received waivers from the lenders and the administrative agent under their existing credit agreements permitting them to divest, in one or more transactions, some or all of its and its subsidiaries' non-nuclear assets without breaching the terms of the agreements. Ratings Triggers Our debt indentures and credit agreements do not contain any material "ratings triggers" that would cause an acceleration of the required interest and principal payments in the event of a ratings downgrade. However, in the event of a downgrade, any one or more of the affected companies may be subject to increased interest costs on certain bank debt and certain collateral requirements. In the event that we are not able to affirm representations and warranties on credit agreements, lenders would not be required to make loans. In accordance with BPU requirements under the BGS contracts, PSE&G is required to maintain an investment grade credit rating. If PSE&G were to lose its investment grade rating, it would be required to file a plan to assure continued payment for the BGS requirements of its customers. Fluctuations in commodity prices or a deterioration ofPSEG Power's credit rating to below investment grade could increasePSEG Power's required margin postings under various agreements entered into in the normal course of business.PSEG Power believes it has sufficient liquidity to meet the required posting of collateral which would likely result from a credit rating downgrade to below investment grade by S&P or Moody's at today's market prices.
Common Stock Dividends
Years Ended
Dividend Payments on Common Stock 2021 2020 2019
Per Share $ 2.04 $ 1.96 $ 1.88
in Millions $ 1,031 $ 991 $ 950
On February 15, 2022 , our Board of Directors approved a $0.54 per share common
stock dividend for the first 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 8. Note 24. Earnings Per Share
(EPS) and Dividends.
Credit Ratings
If the rating agencies lower or withdraw our credit ratings, such revisions may
adversely affect the market price of our securities and serve to materially
increase our cost of capital and limit access to capital. Credit Ratings shown
are for securities that we typically issue. Outlooks are shown for 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.
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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
Other Comprehensive Income
For the year endedDecember 31, 2021 , we had Other Comprehensive Income of$154 million on a consolidated basis. The Other Comprehensive Income was due primarily to an increase of$190 million related to pension and other postretirement benefits, and$3 million of unrealized gains on derivative contracts accounted for as hedges, partially offset by$39 million of net unrealized losses related toAvailable-for-Sale Debt Securities . See Item 8. Note 23. Accumulated Other Comprehensive Income (Loss), Net of Tax for additional information.
CAPITAL REQUIREMENTS
We expect that all of our capital requirements over the next three years will come from a combination of internally generated funds and external debt financing. Projected capital construction and investment expenditures, excluding nuclear fuel purchases, for the next three years are presented in the following table. These projections include AFUDC forPSE&G and Interest Capitalized During Construction for PSEG's other subsidiaries. These amounts are subject to change, based on various factors. Amounts shown below for PSE&G include currently approved programs. We intend to continue to invest in infrastructure modernization and will seek to extend these and related programs as appropriate. 2022 2023 2024 Millions PSE&G: Transmission$ 865 $ 800 $ 595 Electric Distribution 840 1,185 810 Gas Distribution 940 1090 735 Clean Energy 275 390 390 Total PSE&G$ 2,920 $ 3,465 $ 2,530 Other 140 180 210 Total PSEG$ 3,060 $ 3,645 $ 2,740 PSE&G PSE&G's projections for future capital expenditures include material additions and replacements to its T&D systems to meet expected growth and to manage reliability. As project scope and cost estimates develop, PSE&G will modify its current projections to include these required investments. PSE&G's projected expenditures for the various items reported above are primarily comprised of the following:
•Transmission-investments focused on reliability improvements and replacement of aging infrastructure.
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•Electric and Gas Distribution-investments for new business, reliability improvements, flood mitigation, and modernization and replacement of equipment that has reached the end of its useful life.
•Clean Energy-investments associated with customer energy efficiency programs, infrastructure supporting electric vehicles and grid-connected solar.
In 2021, PSE&G made$2,447 million of capital expenditures, primarily for T&D system reliability. This does not include expenditures for cost of removal, net of salvage, of$121 million , which are included in operating cash flows.
Other
PSEG's other projected expenditures are primarily comprised of investments to
replace major parts and enhance operational performance at
In 2021, PSEG's other capital expenditures were$115 million , excluding$157 million for nuclear fuel, primarily related to various nuclear projects atPSEG Power . Offshore Wind The above table does not reflect our expected long-term investments in offshore wind projects. We currently expect to make investments in our 25% equity interest in Orsted'sOcean Wind project to fund construction and operations planning activities. Over the course of the project, which is expected to achieve full commercial operation in 2025, our investments are expected to be substantial. We have planned funding of approximately$250 million to support continued project development to its final investment decision. At that time, if we choose not to proceed with the project, Orsted has the option to repurchase our 25% equity interest in order to proceed with the project.
Other Material Cash Requirements
The following table reflects our other material cash requirements which include
debt maturities and interest payments, operating lease payments and energy
related purchase commitments in the respective periods in which they are due.
For additional information, see Item 8. Note 16. Debt and Credit Facilities,
Note 8. Leases and Note 15. Commitments and Contingent Liabilities.
The table below does not reflect any anticipated cash payments for pension and
OPEB or asset retirement obligations due to uncertain timing of payments. See
Item 8. Note 14. Pension and Other Postretirement Benefits (OPEB) and Savings
Plans and Note 13. Asset Retirement Obligations (AROs) for additional
information.
Total Less
Amount Than 2 - 3 4 - 5 Over
Committed 1 Year Years Years 5 Years
MillionsLong-Term Recourse Debt Maturities
PSEG $ 4,146 $ 700 $ 1,500 $ 550 $ 1,396
PSE&G 11,890 - 1,575 1,225 9,090
Interest on Recourse Debt
PSEG 444 86 118 75 165
PSE&G 6,726 407 781 694 4,844
Operating Leases
PSE&G 117 15 22 17 63
Other 152 25 36 31 60
Energy-Related Purchase Commitments
PSEG Power 2,274 697 825 494 258
Total $ 25,749 $ 1,930 $ 4,857 $ 3,086 $ 15,876
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Table of Contents CRITICAL ACCOUNTING ESTIMATES Under accounting guidance generally accepted inthe United States (GAAP), many accounting standards require the use of estimates, variable inputs and assumptions (collectively referred to as estimates) that are subjective in nature. Because of this, differences between the actual measure realized versus the estimate can have a material impact on results of operations, financial position and cash flows. We have determined that the following estimates are considered critical to the application of rules that relate to the respective businesses.
Accounting for Pensions and Other Postretirement Benefits (OPEB)
The market-related value of plan assets held for the qualified pension and OPEB
plans is equal to the fair value of these assets as of year-end. The plan assets
are comprised of investments in both debt and equity securities which are valued
using quoted market prices, broker or dealer quotations, or alternative pricing
sources with reasonable levels of price transparency. Plan assets also include
investments in unlisted real estate which is valued via third-party appraisals.
We calculate pension and OPEB costs using various economic and demographic
assumptions.
Assumptions and Approach Used: Economic assumptions include the discount rate
and the long-term rate of return on trust assets. Demographic pension and OPEB
assumptions include projections of future mortality rates, pay increases and
retirement patterns, as well as projected health care costs for OPEB.
Assumption 2021 2020 2019
Pension
Discount Rate 2.94 % 2.61 % 3.30 %
Expected Rate of Return on Plan Assets 7.70 % 7.70 % 7.80 %
OPEB
Discount Rate 2.82 % 2.46 % 3.20 %
Expected Rate of Return on Plan Assets 7.69 % 7.70 % 7.79 %
The discount rate used to calculate pension and OPEB obligations is determined
as of December 31 each year, our measurement date. The discount rate is
determined by developing a spot rate curve based on the yield to maturity of a
universe of high quality corporate bonds with similar maturities to the plan
obligations. The spot rates are used to discount the estimated plan
distributions. The discount rate is the single equivalent rate that produces the
same result as the full spot rate curve.
Our expected rate of return on plan assets reflects current asset allocations,
historical long-term investment performance and an estimate of future long-term
returns by asset class, long-term inflation assumptions and a premium for active
management.
We utilize a corridor approach that reduces the volatility of reported
costs/credits. The corridor requires differences between actuarial assumptions
and plan results be deferred and amortized as part of the costs/credits. This
occurs only when the accumulated differences exceed 10% of the greater of the
benefit obligation or the fair value of plan assets as of each year-end. For the
Pension Plan, the excess would be amortized over the average remaining expected
life of inactive participants, which is approximately nineteen years. For
Pension Plan II, the excess would be amortized over the average remaining
service period of active employees, which is approximately fourteen years.
Effect if Different Assumptions Used: As part of the business planning process,
we have modeled future costs assuming a 7.20% expected rate of return and a
2.94% discount rate for 2022 pension costs/credits and a 2.82% discount rate for
2022 OPEB costs/credits. Based upon these assumptions, we have estimated a net
periodic pension credit in 2022 of approximately $115 million , or $172 million ,
net of amounts capitalized, and a net periodic OPEB credit in 2022 of
approximately $124 million , or $127 million , net of amounts capitalized. Actual
future pension costs/credits and funding levels will depend on future investment
performance, changes in discount rates, market conditions, funding levels
relative to our projected benefit obligation and accumulated benefit obligation
and various other factors related to the populations participating in the
pension plans. Actual future OPEB costs/credits will depend on future investment
performance, changes in discount rates, market conditions, and various other
factors.
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The following chart reflects the sensitivities associated with a change in certain assumptions. The effects of the assumption changes shown below solely reflect the impact of that specific assumption.
Impact on Increase to
Benefit Costs, net of
Obligation as Amounts
of December 31, Increase to Costs in Capitalized in
% Change 2021 2022 2022
Assumption Millions
Pension
Discount Rate (1)% $ 945 $ 32 $ 21
Expected Rate of Return on
Plan Assets (1)% N/A $ 67 $ 67
OPEB
Discount Rate (1)% $ 131 $ 15 $ 15
Expected Rate of Return on
Plan Assets (1)% N/A $ 6 $ 6
See Item 7A. Quantitative and Qualitative Disclosures About Market Risk for additional information.
Derivative Instruments
The operations of PSEG,PSEG Power and PSE&G are exposed to market risks from changes in commodity prices, interest rates and equity prices that could affect their results of operations and financial condition. Exposure to these risks is managed through normal operating and financing activities and, when appropriate, through executing derivative transactions. Derivative instruments are used to create a relationship in which changes to the value of the assets, liabilities or anticipated transactions exposed to market risks are expected to be offset by changes in the value of these derivative instruments.
Current accounting guidance requires us to recognize all derivatives on the balance sheet at their fair value, except for derivatives that qualify for and are designated as normal purchases and normal sales contracts.
Assumptions and Approach Used: In general, the fair value of our derivative instruments is determined primarily by end of day clearing market prices from an exchange, such as theNew York Mercantile Exchange , Intercontinental Exchange and Nodal Exchange, or auction prices. Fair values of other energy contracts may be based on broker quotes.
For a small number of contracts where limited observable inputs or pricing information are available, modeling techniques are employed in determination of their fair value using assumptions reflective of contractual terms, current market rates, forward price curves, discount rates and risk factors, as applicable.
For our wholesale energy business, many of the forward sale, forward purchase,
option and other contracts are derivative instruments that hedge commodity price
risk, but do not meet the requirements for, or are not designated as, either
cash flow or fair value hedge accounting. The changes in value of such
derivative contracts are marked to market through earnings as the related
commodity prices fluctuate. As a result, our earnings may experience significant
fluctuations depending on the volatility of commodity prices.
Effect if Different Assumptions Used: Any significant changes to the fair market
values of our derivatives instruments could result in a material change in the
value of the assets or liabilities recorded on our Consolidated Balance Sheets
and could result in a material change to the unrealized gains or losses recorded
in our Consolidated Statements of Operations.
For additional information regarding Derivative Financial Instruments, see
Item 8. Note 1. Organization, Basis of Presentation and Summary of Significant
Accounting Policies, Note 18. Financial Risk Management Activities and Note 19.
Fair Value Measurements.
Long-Lived Assets
Management evaluates long-lived assets for impairment and reassesses the
reasonableness of their related estimated useful lives whenever events or
changes in circumstances warrant assessment. Such events or changes in
circumstances may be as a result of significant adverse changes in regulation,
business climate, counterparty credit worthiness, market conditions, or a
determination that it is more-likely-than-not that an asset or asset group will
be sold or retired before the end of its estimated useful life.
Assumptions and Approach Used: In the event certain triggers exist indicating an
asset/asset group may not be recoverable, an undiscounted cash flow test is
performed to determine if an impairment exists. When the carrying value of a
long-lived asset/asset group exceeds the undiscounted estimate of future cash
flows associated with the asset/asset group, an impairment may exist to the
extent that the fair value of the asset/asset group is less than its carrying
amount.
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For PSEG, cash flows for long-lived assets and asset groups are determined at the lowest level for which identifiable cash flows are largely independent of the cash flows of other assets and liabilities. The cash flows from the generation units are evaluated at the ISO regional portfolio level and, effective inAugust 2021 for PJM assets, do not include PSEG's fossil generating assets as they are classified as Held for Sale. In certain cases, generation assets are evaluated on an individual basis where those assets are individually contracted on a long-term basis with a third party and operations are independent of other generation assets such asPSEG Power's Kalaeloa facility. These tests require significant estimates and judgment when developing expected future cash flows. Significant inputs include, but are not limited to, forward power prices (including ZEC payments for theNew Jersey nuclear assets), fuel costs, dispatch rates, other operating and capital expenditures, the cost of borrowing and asset sale prices and probabilities associated with any potential sale prior to the end of the estimated useful life or the early retirement of assets. The assumptions used by management incorporate inherent uncertainties that are at times difficult to predict and could result in impairment charges or accelerated depreciation in future periods if actual results materially differ from the estimated assumptions utilized in our forecasts. In addition, long-lived assets are depreciated under the straight-line method based on estimated useful lives. An asset's operating useful life is generally based upon operational experience with similar asset types and other non-operational factors. In the ordinary course, management, together with an asset's co-owners in the case of certain of our jointly-owned assets, makes a number of decisions that impact the operation of our generation assets beyond the current year. These decisions may have a direct impact on the estimated remaining useful lives of our assets and will be influenced by the financial outlook of the assets, including future market conditions such as forward energy and capacity prices, operating and capital investment costs and any state or federal legislation and regulations, among other items. Effect if Different Assumptions Used: The above cash flow tests, and fair value estimates and estimated remaining useful lives may be impacted by a change in the assumptions noted above and could significantly impact the outcome, triggering additional impairment tests, write-offs or accelerated depreciation. For additional information on the potential impacts on our future financial statements that may be caused by a change in the assumptions noted above, see Item 8. Note 4. Early Plant Retirements/Asset Dispositions and Impairments.
Asset Retirement Obligations (ARO)
PSE&G,PSEG Power and Services recognize liabilities for the expected cost of retiring long-lived assets for which a legal obligation exists. These AROs are recorded at fair value in the period in which they are incurred and are capitalized as part of the carrying amount of the related long-lived assets. PSE&G, as a rate-regulated entity, recognizes Regulatory Assets or Liabilities as a result of timing differences between the recording of costs and costs recovered through the rate-making process. We accrete the ARO liability to reflect the passage of time with the corresponding expense recorded in O&M Expense. Assumptions and Approach Used: Because quoted market prices are not available for AROs, we estimate the initial fair value of an ARO by calculating discounted cash flows that are dependent upon various assumptions, including:
•estimation of dates for retirement, which can be dependent on environmental and other legislation,
•amounts and timing of future cash expenditures associated with retirement, settlement or remediation activities,
•discount rates, •cost escalation rates, •market risk premium, •inflation rates, and
•if applicable, past experience with government regulators regarding similar obligations.
We obtain updated nuclear decommissioning cost studies triennially unless new information necessitates more frequent updates. The most recent cost study was done in 2021. When we revise any assumptions used to calculate fair values of existing AROs, we adjust the ARO balance and corresponding long-lived asset which generally impacts the amount of accretion and depreciation expense recognized in future periods.
Nuclear Decommissioning AROs
AROs related to the future decommissioning ofPSEG Power's nuclear facilities comprised more than 75% or$1,201 million of PSEG's total AROs as ofDecember 31, 2021 .PSEG Power determines its AROs for its nuclear units by assigning probability weighting to various discounted cash flow outcomes for each of its nuclear units that incorporate the assumptions above as well as:
•financial feasibility and impacts on potential early shutdown,
•license renewals,
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•SAFSTOR alternative, which assumes the nuclear facility can be safely stored and subsequently decommissioned in a period within 60 years after operations,
•DECON alternative, which assumes decommissioning activities begin after operations, and
•recovery from the federal government of assumed specific costs incurred for spent nuclear fuel.
Effect if Different Assumptions Used: Changes in the assumptions could result in a material change in the ARO balance sheet obligation and the period over which we accrete to the ultimate liability. As ofDecember 31, 2021 , assumed market discount rates were historically low; therefore, changes in assumptions may have a more significant impact on the recorded ARO. Had the following assumptions been applied, our estimates of the approximate impacts on the Nuclear ARO as ofDecember 31, 2021 are as follows:
•A decrease of 1% in the discount rate would result in a
•An increase of 1% in the inflation rate would result in a
•If the federal government were to discontinue reimbursing us for assumed
specific spent fuel costs as prescribed under the Nuclear Waste Policy Act, the
Nuclear ARO would increase by
•If we would elect or be required to decommission under a DECON alternative at
•If PSEG Power were to increase its early shutdown probability to 100% and retireSalem 1 andHope Creek starting in 2025 andSalem 2 in 2026, which is significantly earlier than the end of their current license periods, the Nuclear ARO would increase by$698 million . For additional information, see Item 8. Note 4. Early Plant Retirements/Asset Dispositions and Impairments.
Accounting for Regulated Businesses
PSE&G prepares its financial statements to comply with GAAP for rate-regulated enterprises, which differs in some respects from accounting for non-regulated businesses. In general, accounting for rate-regulated enterprises should reflect the economic effects of regulation. As a result, a regulated utility is required to defer the recognition of costs (Regulatory Asset) or recognize obligations (Regulatory Liability) if the rates established are designed to recover the costs and if the competitive environment makes it probable that such rates can be charged or collected. This accounting results in the recognition of revenues and expenses in different time periods than that of enterprises that are not regulated. Assumptions and Approach Used: PSE&G recognizes Regulatory Assets where it is probable that such costs will be recoverable in future rates from customers and Regulatory Liabilities where it is probable that refunds will be made to customers in future billings. The highest degree of probability is an order from the BPU either approving recovery of the deferred costs over a future period or requiring the refund of a liability over a future period.
Virtually all of PSE&G's Regulatory Assets and Regulatory Liabilities are supported by BPU orders. In the absence of an order, PSE&G will consider the following when determining whether to record a Regulatory Asset or Liability:
•past experience regarding similar items with the BPU,
•treatment of a similar item in an order by the BPU for another utility,
•passage of new legislation, and
•recent discussions with the BPU.
All deferred costs are subject to prudence reviews by the BPU. When the recovery of a Regulatory Asset or payment of a Regulatory Liability is no longer probable, PSE&G charges or credits earnings, as appropriate.
Effect if Different Assumptions Used: A change in the above assumptions may result in a material impact on our results of operations or our cash flows. See Item 8. Note 7. Regulatory Assets and Liabilities for a description of the amounts and nature of regulatory balance sheet amounts.
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