EDGAR 10-K Filing

Company CIK: 788784
Filing Year: 2021
Filename: 788784_10-K_2021_0000788784-21-000007.json

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ITEM 1. BUSINESS
ITEM 1. BUSINESS
We were incorporated under the laws of the State of New Jersey in 1985 and our principal executive offices are located at 80 Park Plaza, Newark, New Jersey 07102. We principally conduct our business through two direct wholly owned subsidiaries, PSE&G and PSEG Power, each of which also has its principal executive offices at 80 Park Plaza, Newark, New Jersey 07102.
We are an energy company with a diversified business mix. Our operations are located primarily in the Northeastern and Mid- Atlantic United States. Our business approach focuses on operational excellence, financial strength and disciplined investment. As a holding company, our profitability depends on our subsidiaries’ operating results. Below are descriptions of our two principal direct operating subsidiaries.
PSE&G PSEG Power
A New Jersey corporation, incorporated in 1924, which is a franchised public utility in New Jersey. It is also the provider of last resort for gas and electric commodity service for end users in its service territory.
Earns revenues from its regulated rate tariffs under which it provides electric transmission and electric and natural gas distribution to residential, commercial and industrial customers in its service territory. It also offers appliance services and repairs to customers throughout its service territory.
Also invests in regulated solar generation projects and regulated energy efficiency and related programs in New Jersey.
A Delaware limited liability company formed in 1999 as a result of the deregulation and restructuring of the electric power industry in New Jersey. It integrates the operations of its merchant nuclear and fossil generating assets with its power marketing businesses and fuel supply functions through competitive energy sales in well-developed energy markets.
Earns revenues from the generation and marketing of power and natural gas to hedge business risks and optimize the value of its portfolio of power plants, other contractual arrangements and oil and gas storage facilities. This is achieved primarily by selling power and transacting in natural gas and other energy-related products, on the spot market or using short-term or long-term contracts for physical and financial products.
Also earns revenues from solar generation facilities under long-term sales contracts for power and environmental products.
Our other direct wholly owned subsidiaries are: PSEG Long Island LLC (PSEG LI), which operates the Long Island Power Authority’s (LIPA) electric transmission and distribution (T&D) system under a contractual agreement; PSEG Energy Holdings L.L.C. (Energy Holdings), which earns its revenues primarily from its portfolio of lease investments and holds our investments in offshore wind ventures; and PSEG Services Corporation (Services), which provides us and our operating subsidiaries with certain management, administrative and general services at cost.
BUSINESS OPERATIONS AND STRATEGY
PSE&G
Our regulated T&D public utility, PSE&G, distributes electric energy and natural gas to customers within a designated service territory running diagonally across New Jersey where approximately 6.2 million people, or about 70% of New Jersey’s population resides.
Products and Services
Our utility operations primarily earn margins through the T&D of electricity and the distribution of gas.
•Transmission-the movement of electricity at high voltage from generating plants to substations and transformers, where it is then reduced to a lower voltage for distribution to homes, businesses and industrial customers. Our revenues for these services are based upon tariffs approved by the Federal Energy Regulatory Commission (FERC).
•Distribution-the delivery of electricity and gas to the retail customer’s home, business or industrial facility. Our revenues for these services are based upon tariffs approved by the New Jersey Board of Public Utilities (BPU).
The commodity portion of our utility business’ electric and gas sales is managed by basic generation service (BGS) and basic gas supply service (BGSS) suppliers. Pricing for those services is set by the BPU as a pass-through, resulting in no margin for our utility operations.
We also earn margins through competitive services, such as appliance repair, in our service territory.
In addition to our current utility products and services, we have implemented several programs to invest in regulated solar generation within New Jersey, including:
•programs to help finance the installation of solar power systems throughout our electric service area, and
•programs to develop, own and operate solar power systems.
We have also implemented a set of energy efficiency programs to encourage conservation and energy efficiency by providing energy and cost-saving measures directly to businesses and families.
How PSE&G Operates
We are a transmission owner in PJM Interconnection, L.L.C. (PJM) and we provide distribution service to 2.3 million electric customers and 1.9 million gas customers in a service area that covers approximately 2,600 square miles running diagonally across New Jersey. We serve the most densely populated, commercialized and industrialized territory in New Jersey, including its six largest cities and approximately 300 suburban and rural communities.
Transmission
We use formula rates for our transmission cost of service and investments. Formula rates provide a method of rate recovery where the transmission owner annually determines its revenue requirements through a fixed formula that considers Operation and Maintenance expenditures, rate base and capital investments and applies an approved return on equity (ROE) in developing the weighted average cost of capital. Under this formula, rates are put into effect in January of each year based upon our internal forecast of annual expenses and capital expenditures. Rates are subsequently trued up to reflect actual annual expenses and capital expenditures. Our current approved rates provide for a base ROE of 11.18% on existing and new transmission investment, while certain investments are entitled to earn an additional incentive rate. See Item 7. MD&A-Executive Overview of 2020 and Future Outlook.
We continue to invest in transmission projects that are included for review in the FERC-approved PJM transmission expansion process. These projects focus on reliability improvements and replacement of aging infrastructure with planned capital spending of $2.5 billion for transmission in 2021-2023 as disclosed in Item 7. MD&A-Capital Requirements.
Distribution
PSE&G distributes electricity and natural gas to end users in our respective franchised service territories. In October 2018, the BPU issued an Order approving the settlement of our distribution base rate proceeding with new rates effective November 1, 2018. The Order provides for a distribution rate base of $9.5 billion, a 9.60% ROE for our distribution business and a 54% equity component of our capitalization structure. The BPU has also approved a series of PSE&G infrastructure, energy efficiency, electric vehicle and renewable energy investment programs with cost recovery through various clause mechanisms. For a discussion of proposed and approved programs, see Item 7. MD&A-Executive Overview of 2020 and Future Outlook. Our load requirements are split among residential, commercial and industrial (C&I) customers, as described in the following table for 2020:
% of 2020 Sales
Customer Type Electric Gas
Commercial 56% 36%
Residential 35% 60%
Industrial 9% 4%
Total 100% 100%
Our customer base has modestly increased since 2016, with electric and gas loads changing as illustrated below:
Electric and Gas Distribution Statistics
December 31, 2020
Number of
Customers Electric Sales and Firm Gas
Sales (A) Historical Annual Load Growth 2016-2020
Electric 2.3 Million 39,666 Gigawatt hours (GWh) (1.0)%
Gas 1.9 Million 2,370 Million Therms (1.2)%
(A)Excludes sales from Gas rate classes that do not impact margin, specifically Contract, Non-Firm Transportation, Cogeneration Interruptible and Interruptible Services.
Electric sales declined due to the economic impact of the ongoing coronavirus pandemic (COVID-19) on commercial usage, greater conservation, more energy efficient appliances and increases in solar net metering installations, partially offset by an increase in residential sales due to customers staying at home during the pandemic and customer growth. Firm gas sales decreased as a result of warmer weather in 2020 and lower commercial customer usage due to the pandemic, partially offset by an increase in residential sales due to the pandemic, customer growth and customer response to continued low gas prices. Only firm gas sales impact margin.
Solar Generation
We have undertaken two major solar initiatives at PSE&G, the Solar Loan Program and the Solar 4 All® Programs. Our Solar Loan Program provides solar system financing to our residential and commercial customers. The loans are repaid with cash or solar renewable energy certificates (SRECs). We sell the SRECs received through periodic auctions and use the proceeds to offset program costs. Our Solar 4 All® Programs invest in utility-owned solar photovoltaic (PV) grid-connected solar systems installed on PSE&G property and third-party sites, including landfill facilities, and solar panels installed on distribution system poles in our electric service territory. We sell the energy from the systems in the PJM wholesale electricity market. In addition, we sell SRECs generated by the projects through the same periodic auction used in the Solar Loan program, the proceeds of which are used to offset program costs.
Supply
Although commodity revenues make up almost 34% of our revenues, we make no margin on the default supply of electricity and gas since the actual costs are passed through to our customers.
All electric and gas customers in New Jersey have the ability to choose their electric energy and/or gas supplier. Pursuant to BPU requirements, we serve as the supplier of last resort for two types of electric and gas customers within our service territory that are not served by another supplier. The first type, which represents about 79% of PSE&G’s load requirements, provides default supply service for smaller C&I customers and residential customers at seasonally-adjusted fixed prices for a three-year term (BGS-Residential Small Commercial Pricing (RSCP)). These rates change annually on June 1 and are based on the average price obtained at auctions in the current year and two prior years. The second type provides default supply for larger customers, with energy priced at hourly PJM real-time market prices for a contract term of 12 months (BGS-Commercial Industrial Energy Pricing).
We procure the supply to meet our BGS obligations through auctions authorized by the BPU for New Jersey’s total BGS requirement. These auctions take place annually in February. Results of these auctions determine which energy suppliers are authorized to supply BGS to New Jersey’s electric distribution companies (EDCs). Once validated by the BPU, electricity prices for BGS service are set. Approximately one-third of PSE&G’s total BGS-RSCP eligible load is auctioned each year for a three-year term. For information on current prices, see Item 8. Note 15. Commitments and Contingent Liabilities.
PSE&G procures the supply requirements of its default service BGSS gas customers through a full-requirements contract with PSEG Power. The BPU has approved a mechanism designed to recover all gas commodity costs related to BGSS for residential customers. BGSS filings are made annually by June 1 of each year, with an effective date of October 1. PSE&G’s revenues are matched with its costs using deferral accounting, with the goal of achieving a zero cumulative balance by September 30 of each year. In addition, we have the ability to put in place two self-implementing BGSS increases on December 1 and February 1 of up to 5% and also may reduce the BGSS rate at any time and/or provide bill credits. Any difference between rates charged under the BGSS contract and rates charged to our residential customers is deferred and collected or refunded through adjustments in future rates. C&I customers that do not select third-party suppliers are also supplied under the BGSS arrangement. These customers are charged a market-based price largely determined by prices for commodity futures contracts.
Markets and Market Pricing
Historically, there has been significant volatility in commodity prices. Such fluctuations can have a considerable impact on us since a rising commodity price environment results in higher delivered electric and gas rates for customers. This could result in decreased demand for electricity and gas, increased regulatory pressures and greater working capital requirements as the collection of higher commodity costs from our customers may be deferred under our regulated rate structure. A declining commodity price, on the other hand, would be expected to have the opposite effect.
PSEG Power
Through PSEG Power, we have sought to produce low-cost electricity by efficiently operating our nuclear, gas, oil-fired and renewable generation assets while balancing generation output, fuel requirements and supply obligations through energy portfolio management. Our commitments for load, such as BGS in New Jersey and other bilateral supply contracts, are backed by the generation we own and may be combined with the use of physical commodity purchases and financial instruments from the market to optimize the economic efficiency of serving the load. PSEG Power is a public utility within the meaning of the Federal Power Act (FPA) and the payments it receives and how it operates are subject to FERC regulation.
PSEG Power is also subject to certain regulatory requirements imposed by state utility commissions such as those in New York and Connecticut.
In July 2020, we announced that we are exploring strategic alternatives for PSEG Power’s non-nuclear generating fleet with the intention of accelerating the transformation of our business into a primarily regulated electric and gas utility, with a contracted generation business. See Item 8. Note 4. Early Plant Retirements/Asset Dispositions for further discussion.
Products and Services
As a merchant generator and power marketer, our revenue is derived from selling a range of products and services under contract to an array of customers, including utilities, other power marketers, such as retail energy providers, or counterparties in the open market. These products and services may be transacted bilaterally or through exchange markets and include but are not limited to:
•Energy-the electrical output produced by generation plants that is ultimately delivered to customers for use in lighting, heating, air conditioning and operation of other electrical equipment. Energy is our principal product and is priced on a usage basis, typically in cents per kilowatt hour or dollars per megawatt hour (MWh).
•Capacity-distinct from energy, capacity is a market commitment that a given generation unit will be available to an Independent System Operator (ISO) for dispatch to produce energy when it is needed to meet system demand. Capacity is typically priced in dollars per MW for a given sale period (e.g. day or month).
•Ancillary Services-related activities supplied by generation unit owners to the wholesale market that are required by the ISO to ensure the safe and reliable operation of the bulk power system. Owners of generation units may bid units into the ancillary services market in return for compensatory payments. Costs to pay generators for ancillary services are recovered through charges collected from market participants.
•Congestion and Renewable Energy Credits-Congestion credits (or Financial Transmission Rights) are financial instruments that entitle the holder to a stream of revenues (or charges) based on the hourly congestion price differences across a transmission path. Renewable Energy Credits (RECs) are obtained through PSEG Power’s owned renewable generation or purchased in the open market. Electric suppliers of load are required to deliver a certain amount or percentage of their delivered power from renewable resources as mandated by applicable regulatory requirements.
PSEG Power also sells wholesale natural gas, primarily through a full-requirements BGSS contract with PSE&G to meet the gas supply requirements of PSE&G’s customers. In 2014, the BPU approved an extension of the long-term BGSS contract to March 31, 2019, and thereafter the contract remains in effect unless terminated by either party with a two-year notice.
Approximately 48% of PSE&G’s peak daily gas requirements is provided from PSEG Power’s firm gas transportation capacity. PSEG Power satisfies the remainder of PSE&G’s requirements from storage contracts, contract peaking supply, liquefied natural gas and propane. Based upon the availability of natural gas beyond PSE&G’s daily needs, PSEG Power sells gas to others and uses it for its generation fleet.
PSEG Power also owns and operates 467 MW direct current (dc) of PV solar generation facilities. PSEG Power also has a 50% ownership interest in a 208 MW oil-fired generation facility in Hawaii.
The remainder of this section about PSEG Power covers our nuclear and fossil fleet which comprises the vast majority of PSEG Power’s operations and financial performance.
How PSEG Power’s Generation Operates
Nearly all of our generation capacity is located in the Northeast and Mid-Atlantic regions of the United States in some of the country’s largest and most developed electricity markets. For additional information see Item 2. Properties.
•Capacity
As of December 31, 2020, our fuel mix was comprised of 57% gas, 34% nuclear, 4% coal, and 5% oil. Our total generating output in 2020 was approximately 52,900 GWh. PSEG Power has announced the early retirement of its 383 MW coal unit in Bridgeport, Connecticut in 2021. Including this planned retirement in 2021, PSEG Power will have retired or exited through sales over 2,400 MW of coal-fired generation since 2017.
•Generation Dispatch
Our generation units have historically been characterized as serving one or more of three general energy market segments: base load; load following; and peaking, based on their operating capability and performance.
•Base Load Units run the most and typically are called to operate whenever they are available. These units generally derive revenues from both energy and capacity sales. Variable operating costs are low due to the combination of highly efficient operations and the use of relatively lower-cost fuels. Performance is generally measured by the unit’s “capacity factor,” or the ratio of the actual output to the theoretical maximum output.
•Load Following Units’ operating costs are generally higher per unit of output than for base load units due to the use of higher-cost fuels such as oil and natural gas or lower overall unit efficiency. These units usually have more flexible operating characteristics than base load units which enable them to more easily follow fluctuations in load. They operate less frequently than base load units and derive revenues from energy, capacity and ancillary services.
•Peaking Units run the least amount of time and in some cases may utilize higher-priced fuels. These units typically start very quickly in response to system needs. Costs per unit of output tend to be higher than for base load units given the combination of higher heat rates and fuel costs. The majority of revenues are from capacity and ancillary service sales. The characteristics of these units enable them to capture energy revenues during periods of high energy prices.
In the energy markets in which we operate, owners of power plants specify to the ISO prices at which they are prepared to generate and sell energy based on the marginal cost of generating energy from each individual unit. The ISOs will generally dispatch in merit order, calling on the lowest variable cost units first and dispatching progressively higher-cost units until the point that the entire system demand for power (known as the system “load”) is satisfied reliably. Base load units are dispatched first, with load following units next, followed by peaking units. It should be noted that the sustained lower pricing of natural gas over the past several years has resulted in changes in relative operating costs compared to historical norms, enabling some gas-fired generation to displace some generation by other fuel types. This change, combined with the addition of new, more efficient generation capacity, has altered the historical dispatch order of certain plants in the markets where we operate.
During periods when one or more parts of the transmission grid are operating at full capability, thereby resulting in a constraint on the transmission system, it may not be possible to dispatch units in merit order without violating transmission reliability standards. Under such circumstances, the ISO may dispatch higher-cost generation out of merit order within the congested area, and power suppliers will be paid an increased Locational Marginal Price (LMP) in congested areas, reflecting the bid prices of those higher-cost generation units.
Typically, the bid price of the last unit dispatched by an ISO establishes the energy market-clearing price. After considering the market-clearing price and the effect of transmission congestion and other factors, the ISO calculates the LMP for every location in the system. The ISO pays all units that are dispatched their respective LMP for each MWh of energy produced, regardless of their specific bid prices. Since bids generally approximate the marginal cost of production, units with lower marginal costs typically generate higher gross margins than units with comparatively higher marginal costs.
This method of determining supply and pricing creates a situation where natural gas prices often have a major influence on the price that generators will receive for their output, especially in periods of relatively strong or weak demand. Therefore, changes in the price of natural gas will often translate into changes in the wholesale price of electricity. This can be seen in the following graphs which present historical annual spot prices and forward calendar prices as averaged over each year at two liquid trading hubs.
We expect that the price of natural gas will continue to have a strong influence on the price of electricity in the primary markets in which we operate.
Market wholesale prices may vary by location resulting from congestion or other factors, such as the availability of natural gas from the Marcellus (Leidy) and other shale-gas regions and do not necessarily reflect our contract prices. Forward prices are volatile and there can be no assurance that current forward prices will remain in effect or that we will be able to contract output at these forward prices.
Fuel Supply
•Nuclear Fuel Supply-We have long-term contracts for nuclear fuel. These contracts provide for:
•purchase of uranium (concentrates and uranium hexafluoride),
•conversion of uranium concentrates to uranium hexafluoride,
•enrichment of uranium hexafluoride, and
•fabrication of nuclear fuel assemblies.
•Gas Supply-Natural gas is the primary fuel for the bulk of our load following and peaking fleet. We purchase gas directly from natural gas producers and marketers. These supplies are transported to New Jersey by four interstate pipelines with which we have contracted. In addition, we have firm gas transportation contracted for this winter season to serve a portion of the gas requirements for our Bethlehem Energy Center (BEC) in New York and hold year-round firm gas transportation to serve the majority of the requirements of Keys Energy Center in Maryland.
We have approximately 2.3 billion cubic feet-per-day of firm transportation capacity and firm storage delivery under contract to meet our obligations under the BGSS contract. This volume includes capacity from the Pennsylvania and Ohio shale gas regions where we purchase the majority of our natural gas. On an as-available basis, this firm transportation capacity may also be used to serve the gas supply needs of our New Jersey generation fleet.
•Oil-Oil is used as the primary fuel for one load following steam unit and four combustion turbine peaking units and can be used as an alternate fuel by several load following and peaking units that have a dual-fuel capability. Oil for operations is drawn from on-site storage and is generally purchased on the spot market and delivered by truck or barge.
We expect to be able to meet the fuel supply demands of our customers and our operations. However, the ability to maintain an adequate fuel supply could be affected by several factors not within our control, including changes in prices and demand, curtailments by suppliers, severe weather, environmental regulations, and other factors. For additional information and a discussion of risks, see Item 1A. Risk Factors, Item 7. MD&A-Executive Overview of 2020 and Future Outlook and Item 8. Note 15. Commitments and Contingent Liabilities.
Markets and Market Pricing
The vast majority of PSEG Power’s generation assets are located in three centralized, competitive electricity markets operated by ISO organizations all of which are subject to the regulatory oversight of FERC:
•PJM Regional Transmission Organization-PJM conducts the largest centrally dispatched energy market in North America. The PJM Interconnection coordinates the movement of electricity through all or parts of Delaware, Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia and the District of Columbia. The majority of our generating stations operate in PJM.
•New York-The New York ISO (NYISO) is the market coordinator for New York State and is responsible for managing the New York Power Pool and for administering its energy marketplace. Our BEC generating station operates in New York.
•New England-The ISO-New England (ISO-NE) is the market coordinator for the New England Power Pool and for administering its energy marketplace which covers Maine, New Hampshire, Vermont, Massachusetts, Connecticut and Rhode Island. Our Bridgeport and New Haven stations operate in Connecticut.
The price of electricity varies by location in each of these markets. Depending on our production and our obligations, these price differentials may increase or decrease our profitability.
Commodity prices, such as electricity, gas, oil and environmental products, as well as the availability of our diverse fleet of generation units to operate, also have a considerable effect on our profitability. Over the long-term, the higher the forward prices are, the more attractive an environment exists for us to contract for the sale of our anticipated output. However, higher prices also increase the cost of replacement power; thereby placing us at greater risk should our generating units fail to operate effectively or otherwise become unavailable.
Over the past several years, lower wholesale natural gas prices have resulted in lower electric energy prices. This trend has reduced margin on forward sales as we re-contract our expected generation output.
In addition to energy sales, we earn revenue from capacity payments for our generating assets. These payments are compensation for committing our generating units to the ISO for dispatch at its discretion. Capacity payments reflect the value to the ISO of assurance that there will be sufficient generating capacity available at all times to meet system reliability and energy requirements. See Item 7. MD&A-Executive Overview of 2020 and Future Outlook-Wholesale Power Market Design.
In PJM and ISO-NE, where we operate most of our generation, the market design for capacity payments provides for a structured, forward-looking, capacity pricing mechanism. This is through the Reliability Pricing Model (RPM) in PJM and the Forward Capacity Market (FCM) in ISO-NE. For additional information regarding FERC actions related to the capacity market construct, see Regulatory Issues-Federal Regulation.
The prices to be received by generating units in PJM for capacity have been set through RPM base residual and incremental auctions and depend upon the zone in which the generating unit is located. For each delivery year, the prices differ in the various areas of PJM, depending on the transfer limitations of the transmission system in each area.
Our PJM generating units are located in several zones. The average capacity prices that PSEG Power expects to receive from the base and incremental auctions which have been completed are disclosed in Item 8. Note 3. Revenues. The price that must be paid by an entity serving load in the various zones is also set through these auctions. These prices can be higher or lower than the prices disclosed in Item 8. Note 3. Revenues due to the import and export capability to and from lower-priced areas.
We have obtained price certainty for our PJM capacity through May 2022 through the RPM pricing mechanism and New England capacity through May 2026 for Bridgeport Harbor Unit 5 and May 2024 for New Haven through the FCM pricing mechanism.
Like PJM and ISO-NE, the NYISO provides capacity payments to its generating units, but unlike the other two markets, the New York market does not provide a forward price signal beyond a six-month auction period.
For additional information on the RPM and FCM markets, as well as on state subsidization through various mechanisms, see Regulatory Issues-Federal Regulation.
Hedging Strategy
To mitigate volatility in our results, we seek to contract in advance for a significant portion of our anticipated electric output, capacity and fuel needs. We seek to sell a portion of our anticipated lower-cost generation over a multi-year forward horizon, normally over a period of two to three years. We believe this hedging strategy increases the stability of earnings.
Among the ways in which we have hedged our output are: (1) sales at PJM West or other nodes corresponding to our generation portfolio and (2) physical load sales as full-requirements contracts. Sales in PJM generally reflect block energy sales at the liquid PJM Western Hub or other basis locations when available and other transactions that seek to secure price certainty for our generation related products.
Although we enter into these hedges to provide price certainty for a large portion of our anticipated generation, there is variability in both our actual output as well as in the effectiveness of our hedges. In addition, our use of full requirements contracts as a hedging strategy is expected to decline if the strategic alternatives for PSEG Power’s non-nuclear assets result in a disposition of these assets. Actual output will vary based upon total market demand, the relative cost position of our units compared to other units in the market and the operational flexibility of our units. Hedge volume can also vary, depending on the type of hedge into which we have entered.
Our fuel strategy is to maintain certain levels of uranium in inventory and to make periodic purchases to support such levels. Our nuclear fuel commitments cover approximately 100% of our estimated uranium, enrichment and fabrication requirements through 2021 and a significant portion through 2022.
We take a more opportunistic approach in hedging both the fuel for and the anticipated output of our natural gas-fired generation. The generation from more efficient load following units can be estimated with a moderate degree of certainty. The peaking units are less predictable, as a significant portion of these units will only dispatch when aggregate market demand has exceeded the supply provided by lower-cost units. The natural gas-fired units are hedged based on their expected generation; however, at much lower thresholds than base load generation. Additionally, the availability of low-cost gas supplies in the Marcellus region presents opportunities during certain portions of the year to procure gas for our generating units at attractive prices.
More than 70% of PSEG Power’s expected gross margin in 2021 relates to our hedging strategy, our expected revenues from the capacity market mechanisms described above, ZEC revenues and certain ancillary service payments such as reactive power.
The contracted percentages of our anticipated base load generation output for the next three years are as follows:
Base Load Generation 2021 2022 2023
Generation Sales 100% 65%-70% 30%-35%
Energy Holdings
Lease Investments
Energy Holdings primarily owns and manages a portfolio of domestic lease investments. See Item 8. Note 10. Financing Receivables for additional information.
Offshore Wind
In December 2020, PSEG entered into a definitive agreement with Ørsted North America to acquire a 25% equity interest in Ørsted’s Ocean Wind project. Ocean Wind was selected to be New Jersey’s first offshore wind farm as part of the state’s intention to add 7,500 MW of offshore wind generating capacity by 2035. The Ocean Wind project could provide first power in late 2024. Completion of the acquisition is anticipated to occur in the first half of 2021, subject to approval by the BPU and other customary closing conditions. Additionally, PSEG and Ørsted each owns 50% of Garden State Offshore Energy LLC which holds rights to an offshore wind lease area. PSEG and Ørsted are exploring other offshore wind opportunities.
LIPA Operations Services Agreement
In accordance with a twelve year Amended and Restated Operations Services Agreement (OSA) entered into by PSEG LI and LIPA, PSEG LI commenced operating LIPA’s electric T&D system in Long Island, New York on January 1, 2014. As required by the OSA, PSEG LI also provides certain administrative support functions to LIPA. PSEG LI uses its brand in the Long Island T&D service area. Under the OSA, PSEG LI acts as LIPA’s agent in performing many of its obligations and in return (a) receives reimbursement for pass-through operating expenditures, (b) receives a fixed management fee and (c) is eligible to receive an incentive fee contingent on meeting established performance metrics. Also, there is an opportunity for the parties to extend the contract for an additional eight years subject to the achievement by PSEG LI of certain performance levels during the initial term of the OSA. Further, since January 2015, PSEG Power provides fuel procurement and power management services to LIPA under separate agreements. See Item 7. MD&A-Executive Overview of 2020 and Future Outlook.
COMPETITIVE ENVIRONMENT
PSE&G
Our T&D business is minimally impacted when customers choose alternate electric or gas suppliers since we earn our return by providing T&D service, not by supplying the commodity. Increased reliance by customers on net-metered generation, including solar, and changes in customer behaviors can result in decreased reliance on our system and impact our revenues and investment opportunities. The demand for electric energy and gas by customers is affected by customer conservation, economic conditions, weather and other factors not within our control. Construction of new local generation and changing customer usage patterns also have the potential to reduce the need for the construction of new transmission to transport remote generation and alleviate system constraints. However, our Conservation Incentive Program (CIP), which was recently approved by the BPU as part of our Clean Energy Future-Energy Efficiency (CEF-EE) program, reduces the impact on our distribution revenues from changes in sales volumes and demand for most customers. The CIP, which is calculated annually, provides for a true-up of to our current period revenue as compared to revenue thresholds established in our most recent distribution base rate proceeding. Recovery under the CIP is subject to certain limitations, including an actual versus allowed ROE test and ceilings on customer rate increases. The CIP is effective in June 2021 for electric revenues and October 2021 for gas revenues.
Changes in the current policies for building new transmission lines, such as those ordered by FERC and being implemented by PJM and other ISOs to eliminate contractual provisions that previously provided us a “right of first refusal” to construct projects in our service territory, could result in third-party construction of transmission lines in our area in the future and also allow us to seek opportunities to build in other service territories. These rules continue to evolve so both the extent of the risk within our service territory and the opportunities for our transmission business elsewhere remain difficult to assess. For additional information, see the discussion in Regulatory Issues-Federal Regulation-Transmission Regulation, below.
PSEG Power
Various market participants compete with us and one another in transacting in the wholesale energy markets, entering into bilateral contracts and selling to individual and aggregated retail customers. Our competitors include:
•merchant generators,
•domestic and multi-national utility generators,
•energy marketers and retailers,
•private equity firms, banks and other financial entities,
•fuel supply companies, and
•affiliates of other industrial companies.
New additions of lower-cost or more efficient generation capacity, as well as subsidized generation capacity, could make our plants less economic in the future. Such capacity could impact market prices and our competitiveness.
Our business is also under competitive pressure due to demand-side management (DSM) and other efficiency efforts aimed at changing the quantity and patterns of usage by consumers which could result in a reduction in load requirements. A reduction in load requirements can also be caused by economic cycles, weather and climate change, municipal aggregation and other customer migration and other factors. In addition, how resources such as demand response and capacity imports are permitted to bid into the capacity markets also affects the prices paid to generators such as PSEG Power in these markets. It is also possible that advances in technology, such as distributed generation and micro grids, will reduce the cost of alternative methods of producing electricity to a level that is competitive with that of most central station electric production. To the extent that additions to the electric transmission system relieve or reduce limitations and constraints in eastern PJM where most of our plants are located, our revenues could be adversely affected. Changes in the rules governing what types of transmission will be built, who is selected to build transmission and who will pay the costs of future transmission could also impact our generation revenues.
Adverse changes in energy industry law, policies and regulation could have significant economic, environmental and reliability consequences. For example, PJM, NYISO and ISO-NE each have capacity markets that have been approved by FERC. FERC regulates these markets and continues to examine whether the market design for each of these three capacity markets is working optimally. Various forums are considering how the competitive market framework can incorporate or be reconciled with state public policies that support particular resources, resource attributes or emerging technologies, whether generators are being sufficiently compensated in the capacity market and whether subsidized resources may be adversely affecting capacity market prices. For information regarding recent actions by FERC relating to capacity market design, see the discussion in Regulatory Issues-Federal Regulation.
Environmental issues, such as restrictions on emissions of carbon dioxide (CO2) and other pollutants, may also have a competitive impact on us to the extent that it becomes more expensive for some of our plants to remain compliant, thus affecting our ability to be a lower-cost provider compared to competitors without such restrictions. In addition, most of our plants, which are located in the Northeast where rules are more stringent, can be at an economic disadvantage compared to our competitors in certain Midwest states.
While it is our expectation that continued efforts may be undertaken by the federal and state governments to preserve the existing base nuclear generating plants, we still believe that pressures from renewable resources will continue to increase.
HUMAN CAPITAL MANAGEMENT
At PSEG, we know that our people are our most valuable resource. Our Human Capital Management objective is to ensure we have the best talent and culture to sustain our business.
PSEG continuously strives for a culture of inclusion that supports its employees, customers and the many diverse communities we serve. Fundamental to our culture are our Core Commitments-safety; integrity; continuous improvement; customer service; and diversity, equity and inclusion. Through these Core Commitments, we seek to attract, develop and retain a diverse, high-performing workforce that drives organizational performance and fosters a culture of collaboration, learning and comfort speaking up where new ideas are welcome and employees feel valued and enhance each other’s performance.
As of December 31, 2020, PSEG employed 12,788 full-time employees, of which 61% are covered by collective bargaining agreements. Women represent 18% of the PSEG workforce and 26% of our employees are people of color. Of our full-time external hires in 2020, 41% were women or racially/ethnically diverse.
Diversity, Equity and Inclusion
In 2020, PSEG added “equity” to our Diversity & Inclusion commitment. We performed a comprehensive review of our policies and practices, resulting in updates of our programs to better support equity. We expanded our paid parental leave program and have begun to revise our hiring practices to allow greater access to job opportunities. We conduct semi-annual equity reviews of compensation for non-represented employees and incorporate multiple levels of calibration of performance ratings. In 2020, we also launched a disability inclusion campaign to better understand our employee population self-identifying as having a disability.
We have a strong and active Employee Business Resource Group (EBRG) network of over 25 employee groups connected in 12 focus areas Enterprise-wide that is closely aligned to PSEG’s business objectives. These EBRGs encompass groups including, but not limited to, Black Professionals, Asian & Pacific Islanders, Hispanic/LatinX, LGBTQ+, People with Disabilities, New Hires, Women, Working Parents & Caregivers, and Veterans.
Talent Management and Engagement
PSEG is committed to attracting, developing and retaining a robust talent pipeline, from our front lines to our leadership levels. In 2020, we created a women-in-skilled-trades initiative, and are piloting a partnership model with historically Black colleges and universities. Our People Strong training programs provide development at different career levels from our newly hired college graduates and front line supervisors to executive leadership pipeline. In 2020, we trained our top 200+ leaders in developing inclusive leadership skills. We also doubled participation in women’s leadership development programs and pioneered a new program for Black professionals in support of increasing representation in leadership ranks. To support safe and reliable operations, we invest in technical and operational training for our craft and field workers.
We solicit continuous feedback so that we improve our culture in a way that is responsive to the voices of our employees. We conduct surveys, focus groups and listening sessions throughout the year, in addition to our annual Your Voice Matters employee experience survey. In 2020, our overall employee engagement score was 86%, and 88% of employees reported feeling proud to work at PSEG.
Total Rewards
In addition to our competitive pay, incentives and benefits programs, our Total Rewards offerings take into account the safety, health and overall well-being of our employees. We offer an array of programs designed to support physical, emotional, and financial wellness. Our benefits programs are designed to support our employees through everyday challenges, critical life events, and new and changing life experiences. Our programs include access to live therapy, childcare and eldercare resources, voluntary benefits for discounted services, tuition reimbursement and adoption assistance.
Labor Relations
We are proud of the partnership we have with union leadership and the 7,786 employees represented by unions in our workforce. Our strong relationship with our unions allowed for swift and effective implementation of COVID-19 protocols. In 2020, we extended several of our labor contracts through dates in 2023, providing labor stability during the pendency of key business initiatives.
As we accelerate our business to a primarily regulated utility and contracted energy business with zero-carbon nuclear assets, PSEG is committed to a fair, equitable and transparent approach to human capital management, one that is grounded in treating people with dignity and respect. With evolving technologies in energy and digital advancements, we look for training, upskilling and redeployment opportunities for our existing workforce.
COVID-19 Response for Our Employees
In light of the national emergency and global pandemic due to COVID-19, PSEG activated its business continuity plan and enacted new work practices, workplace safety protocols, and expanded employee benefits and support to ensure the safety, health and wellness of our employees. Throughout the pandemic, we have maintained our workforce levels and provided frequent education to frontline managers and the workforce. We implemented remote work practices for all employees whose job could be performed remotely.
A pandemic response hotline was put in place to guide employees through questions about their COVID-19-related health and safety, to provide identification and notification of close contact exposure, and to offer clinical assessments to determine quarantine needs and appropriate return-to-work procedures.
We provided COVID-19 related paid time off for employees to take care of themselves and their family members, get vaccinated and to navigate school and daycare closures. We expanded our bereavement leave practice and enhanced childcare resources to support working parents. We have designed our Responsible Reentry approach and playbook for future business practices.
REGULATORY ISSUES
In the ordinary course of our business, we are subject to regulation by, and are party to various claims and regulatory proceedings with, FERC, the BPU, the Commodity Futures Trading Commission (CFTC) and various state and federal environmental regulators, among others. For information regarding material matters, other than those discussed below, see Item 8. Note 15. Commitments and Contingent Liabilities. In addition, information regarding PSE&G’s specific filings pending before the BPU is discussed in Item 8. Note 7. Regulatory Assets and Liabilities.
Federal Regulation
FERC is an independent federal agency that regulates the transmission of electric energy and natural gas in interstate commerce and the sale of electric energy and natural gas at wholesale pursuant to the FPA and the Natural Gas Act. PSE&G and the generation and energy trading subsidiaries of PSEG Power are public utilities as defined by the FPA. FERC has extensive oversight over such public utilities. FERC approval is usually required when a public utility seeks to: sell or acquire an asset
that is regulated by FERC (such as a transmission line or a generating station); collect costs from customers associated with a new transmission facility; charge a rate for wholesale sales under a contract or tariff; or engage in certain mergers and internal corporate reorganizations.
FERC also regulates generating facilities known as qualifying facilities (QFs). QFs are cogeneration facilities that produce electricity and another form of useful thermal energy, or small power production facilities where the primary energy source is renewable, biomass, waste or geothermal resources. QFs must meet certain criteria established by FERC. We own various QFs through PSEG Power. QFs are subject to some, but not all, of the same FERC requirements as public utilities.
FERC also regulates Regional Transmission Operators (RTOs)/ISOs, such as PJM, and their energy and capacity markets.
Regulation of Wholesale Sales-Generation/Market Issues/Market Power
Under FERC regulations, public utilities that wish to sell power at market rates must receive FERC authorization (market-based rate (MBR) Authority) to sell power in interstate commerce before making power sales. They can sell power at cost-based rates or apply to FERC for authority to make MBR sales. For a requesting company to receive MBR Authority, FERC must first determine that the requesting company lacks market power in the relevant markets and/or that market power in the relevant markets is sufficiently mitigated. Certain PSEG companies are public utilities and currently have MBR Authority.
Energy Clearing Prices
Energy clearing prices in the markets in which we operate are generally based on bids submitted by generating units. Under FERC-approved market rules, bids are subject to price caps and mitigation rules applicable to certain generation units. FERC rules also govern the overall design of these markets. At present, all units within a delivery zone receive a clearing price based on the bid of the marginal unit (i.e. the last unit that must be dispatched to serve the needs of load) which can vary by location. In addition, recent rule changes in the energy markets administered by PJM and ISO-NE (see Capacity Market Issues below) impose rigorous performance obligations and non-performance penalties on resources during times of system stress. These FERC rules provide an opportunity for bonus payments or require the payment of penalties depending on whether a unit is available during a performance hour.
In April 2019, FERC issued an order directing PJM and NYISO to change their rules governing pricing for fast-start resources. In its Order, FERC found that current fast-start pricing practices are unjust and unreasonable because they do not allow prices to reflect the marginal cost of serving load. FERC required PJM and NYISO to make various changes to their respective tariffs to allow the start-up costs of fast-start resources to be reflected in prices, among other things. In August 2019, PJM stated that new tariff provisions would apply fast-start pricing to all eligible fast-start resources. However, in January 2020, FERC decided to hold the proceeding in abeyance in order to allow PJM and its stakeholders to address FERC’s concern that PJM’s pricing and dispatch are misaligned. In December 2020, FERC issued an order accepting aspects of PJM’s proposed reforms, but also directed PJM to submit an additional filing that includes an implementation date. The new rules will not be implemented until FERC issues an order approving PJM’s final compliance filing. We will continue to participate in this proceeding.
In May 2020, FERC issued an order approving PJM’s proposal to modify the curves used for pricing reserves with FERC. The reforms include a consolidation of synchronized reserve products, improved use of existing capability for locational reserve needs, better alignment of reserve products in day-ahead and real-time markets, a downward-sloping operating reserve demand curve, and increased penalty factors to ensure use of all supply prior to a reserve shortage. These reforms will be implemented in May 2022.
In January 2020, New Jersey rejoined the Regional Greenhouse Gas Initiative (RGGI). As a result, generating plants operating in New Jersey that emit CO2 emissions will have to procure credits for each ton that they emit. Other PJM states in RGGI are Maryland, Delaware and Virginia and Pennsylvania continues to investigate joining. PJM initiated a process in 2019 to investigate the development of a carbon pricing mechanism that may mitigate the environmental and financial distortions that could occur when emissions “leak” from non-participating states to the RGGI states. The process is expected to continue through 2021 and if it leads to a market solution, could have a material impact on the value of PSEG Power’s generating fleet.
Capacity Market Issues
PJM, NYISO and ISO-NE each have capacity markets that have been approved by FERC. FERC regulates these markets and continues to examine whether the market design for each of these three capacity markets is working optimally. Various forums are considering how the competitive market framework can incorporate or be reconciled with state public policies that support particular resources, resource attributes or emerging technologies, whether generators are being sufficiently compensated in the capacity market and whether subsidized resources may be adversely affecting capacity market prices. We cannot predict what action, if any, FERC might take with regard to capacity market designs.
PJM-The RPM is the locational installed capacity market design for the PJM region, including a forward auction for installed capacity. Under the RPM, generators located in constrained areas within PJM are paid more for their capacity as an incentive to
ensure adequate supply where generation capacity is most needed. The mechanics of the RPM in PJM continue to evolve and be refined in stakeholder proceedings and FERC proceedings in which we are active.
In December 2019, FERC issued an order establishing new rules for PJM’s capacity market. In this new order, FERC extended the PJM Minimum Offer Price Rule (MOPR), which currently applies to new natural gas-fired generators, to include both new and existing resources that receive or are entitled to receive certain out-of-market payments, with certain exemptions.
PSEG Power’s New Jersey nuclear plants that receive ZEC payments will be subject to the new MOPR. Resources that are subject to the MOPR continue to have the ability to justify a bid below the MOPR floor price under the unit-specific exemption. The MOPR floor prices are not expected to prevent either our nuclear or gas-fired units from clearing in the next RPM auction. In May 2020, FERC issued an order modifying PJM’s methodology for pricing energy reserves. It also directed PJM to use forward-looking energy and ancillary service revenues, which can affect how the MOPR offer floors are calculated. In addition, if one or more electric distribution zones in New Jersey (or another state) were to become fixed resource requirement (FRR) service areas, procurements needed for that area could provide an alternate means for nuclear units whose ability to clear in RPM auctions was affected by the MOPR to provide capacity within PJM.
We cannot predict whether additional changes will be made to the MOPR, or whether changes will occur in the PJM market that would impact our ability to clear any of these units in future RPM auctions.
States that have clean energy programs designed to achieve public policy goals that support such resources as solar, offshore wind and nuclear are not prevented from pursuing those programs by the expanded MOPR and could choose to utilize the existing FRR approach authorized under the PJM tariff. The FRR provides a means other than PJM’s capacity auction for an entity obligated to supply customers to satisfy its capacity obligation. Accordingly, subsidized units that cannot clear in an RPM capacity auction because of the expanded MOPR could still count as capacity resources to a load serving entity using the FRR approach. In a March 2020 order, the BPU initiated an investigation to examine whether New Jersey can achieve its long-term clean energy and environmental objectives under the current resource adequacy procurement paradigm and potential alternatives. One of the areas of inquiry concerns the potential creation of FRR service areas within New Jersey.
ISO-NE-ISO-NE’s market for installed capacity in New England provides fixed capacity payments for generators, imports and demand response. The market design consists of a forward-looking auction for installed capacity that is intended to recognize the locational value of resources on the system and contains incentive mechanisms to encourage availability during stressed system conditions. ISO-NE also employs a mechanism, similar to PJM’s Capacity Performance mechanism, that provides incentives for performance and that imposes charges for non-performance during times of system stress. We view this mechanism as generally positive for generating resources as providing more robust income streams. However, it also imposes additional financial risk for non-performance.
NYISO-NYISO operates a short-term capacity market that provides a forward price signal only for six months into the future. Various matters pending before FERC could affect the competitiveness of this market and the outcome of these proceedings could result in artificial price suppression unless sufficient market protections are adopted.
Transmission Regulation
FERC has exclusive jurisdiction to establish the rates and terms and conditions of service for interstate transmission. We currently have FERC-approved formula rates in effect to recover the costs of our transmission facilities. Under this formula, rates are put into effect in January of each year based upon our internal forecast of annual expenses and capital expenditures. Rates are subsequently trued up to reflect actual annual expenses and capital expenditures.
Transmission Rate Proceedings and Return on Equity-From time to time, various matters are pending before FERC relating to, among other things, transmission planning, reliability standards and transmission rates and returns, including incentives. Depending on their outcome, any of these matters could materially impact our results of operations and financial condition.
In November 2019, FERC issued an order establishing a new ROE policy for reviewing existing transmission ROEs. The new methodology uses the discounted cash flow (DCF) model and capital asset pricing model (CAPM) to determine if an existing base ROE is unjust and unreasonable and, if so, what replacement ROE is appropriate. PSE&G joined the PJM Transmission Owners in requesting rehearing of FERC’s order on the grounds that the new methodology is flawed. In May 2020, FERC partially granted rehearing of the November 2019 order and again revised the ROE methodology by reinstating the risk premium model with the CAPM and DCF models. FERC’s order indicated that it would not be bound by this revised methodology when considering the just and reasonableness of a utility’s ROE in future proceedings. We continue to analyze the potential impact of these methodologies.
ROE complaints have been pending before FERC regarding Midcontinent Independent System Operator (MISO) transmission owners, the ISO New England Inc. transmission owners and utilities in other jurisdictions. In addition, over the past few years, several companies have negotiated settlements that have resulted in reduced ROEs.
We are engaged in settlement discussions with the BPU Staff and the New Jersey Division of Rate Counsel (New Jersey Rate
Counsel) about the level of PSE&G’s base transmission ROE; however, we cannot predict the outcome of these settlement discussions. An adverse change to PSE&G’s base transmission ROE or ROE incentives could be material.
Compliance
Reliability Standards-Congress has required FERC to put in place, through the North American Electric Reliability Corporation (NERC), national and regional reliability standards to ensure the reliability of the U.S. electric transmission and generation system (grid) and to prevent major system blackouts. As a result, FERC directed NERC to draft a physical security standard intended to further protect assets deemed “critical” to reliability of the grid. In July 2015, FERC issued an order approving NERC’s proposed physical security standard. Under the standard, utilities are required to identify critical substations as well as develop threat assessment plans to be reviewed by independent third parties. In our case, the third-party is PJM. As part of these plans, utilities can decide or be required to build additional redundancy into their systems. This standard supplements the Critical Infrastructure Protection standards that are already in place and that establish physical and cybersecurity protections for critical systems. FERC directed NERC to develop a new reliability standard to provide security controls for supply chain management associated with the procurement of industrial control system hardware, software, and services related to grid operations. FERC approved the supply chain management standard in October 2018, with an implementation date of October 1, 2020. We have documented procedures and implemented new processes to comply with these standards.
CFTC
In accordance with the Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act), the SEC and the CFTC are in the process of implementing a new regulatory framework for swaps and security-based swaps. The legislation was enacted to reduce systemic risk, increase transparency and promote market integrity within the financial system by providing for the registration and comprehensive regulation of swap dealers and by imposing recordkeeping, data reporting, margin and clearing requirements with respect to swaps. To implement the Dodd-Frank Act, the CFTC has engaged in a comprehensive rulemaking process and has issued a number of proposed and final rules addressing many of the key issues. We are currently subject to recordkeeping and data reporting requirements applicable to commercial end users. The CFTC has also re-proposed rules establishing position limits for trading in certain commodities, such as natural gas, and we will begin complying with these rules once they become final.
Nuclear
Nuclear Regulatory Commission (NRC)
Our operation of nuclear generating facilities is subject to comprehensive regulation by the NRC, a federal agency established to regulate nuclear activities to ensure the protection of public health and safety, as well as the environment. Such regulation involves testing, evaluation and modification of all aspects of plant operation in light of NRC safety and environmental requirements. Continuous demonstration to the NRC that plant operations meet requirements is necessary.
The NRC has the ultimate authority to determine whether any nuclear generating unit may operate. The NRC conducts ongoing reviews of nuclear industry operating experience and may issue or revise regulatory requirements. We are unable to predict the final outcome of these reviews or the cost of any actions we would need to take to comply with any new regulations, including possible modifications to the Salem, Hope Creek and Peach Bottom facilities, but such costs could be material.
In March 2020, Exelon, co-owner of the Peach Bottom nuclear facilities in Pennsylvania, received approval from the NRC for a second 20-year license renewal for Peach Bottom Units 2 and 3. The current operating licenses of our nuclear facilities expire in the years shown in the following table:
Unit Year
Salem Unit 1 2036
Salem Unit 2 2040
Hope Creek 2046
Peach Bottom Unit 2 2053
Peach Bottom Unit 3 2054
State Regulation
Our principal state regulator is the BPU, which oversees electric and natural gas distribution companies in New Jersey. We are also subject to various other states’ regulations due to our operations in those states.
Our New Jersey utility operations are subject to comprehensive regulation by the BPU including, among other matters, regulation of retail electric and gas distribution rates and service, the issuance and sale of certain types of securities and compliance matters. PSE&G’s participation in solar and energy efficiency programs is also regulated by the BPU, as the terms
and conditions of these programs are approved by the BPU. BPU regulation can also have a direct or indirect impact on our power generation business as it relates to energy supply agreements and energy policy in New Jersey.
In addition to base rates, we recover certain costs or earn on certain investments pursuant to mechanisms known as adjustment clauses. These clauses permit the flow-through of costs to, or the recovery of investments from, customers related to specific programs, outside the context of base rate proceedings. Recovery of these costs or investments is subject to BPU approval for which we make periodic filings. Delays in the pass-through of costs or recovery of investments under these mechanisms could result in significant changes in cash flow.
New Jersey Energy Master Plan (EMP)-In January 2020, the State of New Jersey released its EMP. While the EMP does not have the force of law and does not impose any obligations on utilities, it outlines current expectations regarding the state’s role in the use, management, and development of energy. The EMP recognizes the goals of New Jersey’s Clean Energy Act of 2018 (the Clean Energy Act) of reducing electric and gas consumption by at least 2% and 0.75%, respectively. The EMP outlines several strategies, including statewide energy efficiency programs; expansion of renewable generation (solar and offshore wind), energy storage and other carbon-free technologies; preservation of existing nuclear generation; electrification of the transportation sector; and reduced reliance on natural gas. We cannot predict the impact on our business or results of operations from the EMP or any laws, rules or regulations promulgated as a result thereof, particularly as they may relate to PSEG Power’s nuclear and gas generating stations and PSE&G’s electric transmission and gas distribution assets. We also cannot predict what actions federal government agencies may take in light of the Environmental Protection Agency’s (EPA) Affordable Clean Energy (ACE) rule and other federal initiatives associated with climate change or the impact of any such actions on our business or results of operations.
Concurrently with the release of the EMP, New Jersey Governor Murphy signed an executive order directing the New Jersey Department of Environmental Protection (NJDEP) to establish a greenhouse gas (GHG) monitoring and reporting program, adopt new regulations to reduce CO2 emissions and reform environmental land use regulations to incorporate climate change considerations into permitting decisions. We cannot predict the impact of this executive order.
BGSS Process-In September 2019, the BPU formally opened a stakeholder proceeding to explore gas capacity procurement and related issues with respect to service to all New Jersey natural gas customers, whether served through BGSS or a third- party supplier. In addition, the BPU directed that the proceeding review whether, and to what extent, third-party suppliers are providing savings to New Jersey customers on their natural gas supply. The Board Staff has conducted a public hearing and interested parties, including PSE&G, have submitted oral and written comments while also answering the Staff’s specific questions concerning, among other things, capacity procurement (e.g., timing, price, sufficiency); the sufficiency of pipeline capacity within New Jersey; the cost impacts if gas distribution companies were made responsible for securing incremental capacity for their transportation customers; and economic benefits to residential customers. The proceeding remains open.
BGS Process-In July 2020, the State’s EDCs filed their annual proposal for the conduct of the February 2021 BGS auction covering electric supply for energy years 2022 through 2024. In prior years, the BPU and BGS suppliers expressed concerns regarding transmission costs incurred by BGS participants that are collected from customers but not paid to the BGS suppliers due to several unresolved proceedings at FERC. To address these concerns, the EDCs proposed, among other things, to (a) remove transmission from the BGS product in the upcoming 2021 BGS auction, and (b) amend existing BGS contracts to transfer responsibility for transmission-through the transfer of specific PJM billing line items-from the BGS supplier to the EDCs. In both cases, each EDC will continue to collect transmission costs from its BGS customers as a supply cost. In November 2020, the BPU approved both proposals. As a result, (a) the 2021 BGS auction product excluded the obligation for the BGS suppliers to provide transmission and (b) BGS suppliers now have the option to amend existing BGS contracts to transfer the supplier’s obligation to provide transmission to the EDCs effective February 1, 2021. In November 2020, the BPU also directed the EDCs to enter into agreements with BGS suppliers pursuant to which the EDCs would pay to BGS suppliers certain funds collected from BGS customers notwithstanding the absence of final FERC Orders in certain cases in which transmission cost allocations have been challenged. Previously, the EDCs had collected these funds from customers but withheld payment of these funds to BGS suppliers until the issuance of a final FERC Order. As security to the EDCs, in the event that the cost allocation challenges are ultimately successful and BGS suppliers must return the funds to the EDCs, the BGS suppliers must post a letter of credit in an amount equal to 50% of the payment due the suppliers. Those BGS suppliers that do not choose to receive such funds are not required to enter into agreements or post letters of credit with the EDCs.
New Jersey Solar Initiatives-Pursuant to the Clean Energy Act, the BPU was required to undertake several initiatives in connection with New Jersey’s solar energy market.
The BPU established a “Community Solar Energy Pilot Program,” permitting customers to participate in solar energy projects remotely located from their properties, and allowing for bill credits related to that participation effective in February 2019. The BPU is currently engaged in a stakeholder process with the State’s EDCs and others regarding certain issues, including minor modifications to the community solar pilot program, discussions regarding the potential implementation of consolidated billing for the benefit of project developers and participants, and developing a cost recovery mechanism for the EDCs.
The Clean Energy Act required the BPU to close the existing SREC program to new applications at the earlier of June 1, 2021 or the date at which 5.1% of New Jersey retail electric sales are derived from solar. The 5.1% threshold was attained and the SREC market was closed to new applications on April 30, 2020, with limited exceptions related to the impact of COVID-19 on projects under development. Solar projects that failed to achieve commercial operation before April 30, 2020 may be entitled to receive transition renewable energy certificates (TRECs) for each MWh of solar production. The New Jersey EDCs, including PSE&G, are required to purchase, using the services of a TREC administrator, TRECs from solar projects at rates set by the BPU. PSE&G filed for rate recovery of these costs in April 2020. In August 2020, the BPU approved PSE&G’s rate recovery filing. The BPU is continuing to work with the state’s EDCs to establish the mechanisms for implementing the transition incentive program.
Cybersecurity
In an effort to reduce the likelihood and severity of cybersecurity incidents, we have established a comprehensive cybersecurity program designed to protect and preserve the confidentiality, integrity and availability of our information systems. The Board, the Audit Committee, Industrial Operations Committee and senior management receive frequent reports on such topics as personnel and resources to monitor and address cybersecurity threats, technological advances in cybersecurity protection, rapidly evolving cybersecurity threats that may affect our Company and industry, cybersecurity incident response and applicable cybersecurity laws, regulations and standards, as well as collaboration mechanisms with intelligence and enforcement agencies and industry groups, to assure timely threat awareness and response coordination.
Our cybersecurity program is focused on the following areas:
•Governance
•Cybersecurity Council-which is comprised of members of senior management, meets regularly to discuss emerging cybersecurity issues and maintenance of a corporate cybersecurity scorecard to measure performance of key risk indicators. The Cybersecurity Council ensures that senior management, and ultimately, the Board, is given the information required to exercise proper oversight over cybersecurity risks and that escalation procedures are followed.
•Cybersecurity Excellence Oversight Board (CEOB)-provides the Chief Operating Officer with periodic cybersecurity assessments of PSEG. The CEOB is comprised of employee and non-employee members who have expertise in technology security, compliance and controls, or in management practices.
•Cybersecurity Awareness-Identifying and assessing cyber risks through partnerships with public and private entities and industry groups, and disseminating electronic notices to, and conducting presentations for, company personnel.
•Training-Providing annual cybersecurity training for all personnel with network access, as well as additional education for personnel with access to industrial control systems or customer information systems; and conducting phishing exercises. Regular cybersecurity education is also provided to our Board through management reports and presentations by external subject matter experts.
•Technical Safeguards-Deploying measures to protect our network perimeter and internal Information Technology platforms, such as internal and external firewalls, network intrusion detection and prevention, penetration testing, vulnerability assessments, threat intelligence, anti-malware and access controls.
•Vendor Management-Maintaining a risk-based vendor management program, including the development of robust security contractual provisions. Notably, in 2020, we implemented additional measures to ensure compliance with new requirements promulgated by the NERC applicable to cyber systems involved in the operation of the Bulk Electric System (BES). These new or enhanced measures require PSEG to identify and assess risks to the BES from vendor products or services.
•Incident Response Plans-Maintaining and updating incident response plans that address the life cycle of a cybersecurity incident from a technical perspective (i.e., detection, response, and recovery), as well as data breach response (with a focus on external communication and legal compliance); and testing those plans (both internally and through external exercises).
•Mobile Security-Deploying controls to prevent loss of data through mobile device channels.
PSEG also maintains physical security measures to protect its Operational Technology systems, consistent with a defense in depth and risk-tiered approach. Such physical security measures may include access control systems, video surveillance, around-the-clock command center monitoring, and physical barriers (such as fencing, walls, and bollards). Additional features of PSEG’s physical security program include threat intelligence, insider threat mitigation, background checks, a threat level
advisory system, a business interruption management model, and active coordination with federal, state, and local law enforcement officials. See Regulatory Issues-Federal for a discussion on physical reliability standards that the NERC has promulgated.
In addition, we are subject to federal and state requirements designed to further protect against cybersecurity threats to critical infrastructure, as discussed below. For a discussion of the risks associated with cybersecurity threats, see Item 1A. Risk Factors.
Federal-NERC, at the direction of FERC, has implemented national and regional reliability standards to ensure the reliability of the grid and to prevent major system blackouts. NERC Critical Infrastructure Protection standards establish cybersecurity protections for critical systems and facilities. These standards are also designed to develop coordination, threat sharing and interaction between utilities and various government agencies regarding potential cyber threats against the nation’s electric grid.
FERC further directed NERC to develop a new reliability standard to provide security controls for supply chain management associated with the procurement of industrial control system hardware, software, and services related to bulk electric system operations. FERC approved the supply chain risk management standard in October 2018, with an implementation date of October 1, 2020. We have documented procedures and implemented new processes to comply with these standards.
State-The BPU requires utilities, including PSE&G, to, among other things, implement a cybersecurity program that defines and implements organizational accountabilities and responsibilities for cyber risk management activities, and establishes policies, plans, processes and procedures for identifying and mitigating cyber risk to critical systems. Additional requirements of this order include, but are not limited to: (i) annually inventorying critical utility systems; (ii) annually assessing risks to critical utility systems; (iii) implementing controls to mitigate cyber risks to critical utility systems; (iv) monitoring log files of critical utility systems; (v) reporting cyber incidents to the BPU; and (vi) establishing a cybersecurity incident response plan and conducting biennial exercises to test the plan. In addition, New York’s Stop Hacks and Improve Electronic Data Security (SHIELD) Act, which became effective in March 2020, requires businesses that own or license computerized data that includes New York State residents’ private information to implement reasonable safeguards to protect that information.
ENVIRONMENTAL MATTERS
We are subject to federal, state and local laws and regulations with regard to environmental matters including, but not limited to:
•air pollution control,
•climate change,
•water pollution control,
•hazardous substance liability, and
•fuel and waste disposal.
We expect there will be changes to existing environmental laws and regulations, particularly in light of the change in administration following the 2020 U.S. presidential election that could significantly impact the manner in which our operations are currently conducted. Such laws and regulations may also affect the timing, cost, location, design, construction and operation of new facilities. Due to evolving environmental regulations, it is difficult to project future costs of compliance and their impact on competition. Capital costs of complying with known pollution control requirements are included in our estimate of construction expenditures in Item 7. MD&A-Capital Requirements. The costs of compliance associated with any new requirements that may be imposed by future regulations are not known, but may be material.
For additional information related to environmental matters, including proceedings not discussed below, as well as anticipated expenditures for installation of pollution control equipment, hazardous substance liabilities and fuel and waste disposal costs, see Item 1A. Risk Factors and Item 8. Note 15. Commitments and Contingent Liabilities.
Air Pollution Control
Our facilities are subject to federal regulation under the Clean Air Act that requires controls of emissions from sources of air pollution and imposes recordkeeping, reporting and permit requirements. Our facilities are also subject to requirements established under state and local air pollution laws. The Clean Air Act requires all major sources, such as our generation facilities, to obtain and keep current an operating permit. The costs of compliance associated with any new requirements that may be imposed and included in these permits in the future could be material and are not included in our estimates of capital expenditures.
Environmental Justice-In September 2020, the New Jersey governor signed legislation that enacted an environmental justice process for applicants seeking environmental permits, including those emission permits regulated under Title V of the Clean Air Act, for facilities located in what the law defines as overburdened communities. With this law, New Jersey has embarked on a
path toward a legislative goal that no community should bear “a disproportionate share of the adverse environmental and public health consequences that accompany New Jersey’s economic growth.” The law does not go into effect until the NJDEP adopts implementing regulations. The regulations are anticipated to be finalized by year-end 2021.
Hazardous Air Pollutants Regulation-In February 2012, the EPA published Mercury Air Toxics Standards (MATS) for both newly-built and existing electric generating sources under the National Emission Standard for Hazardous Air Pollutants provisions of the Clean Air Act. The MATS established allowable levels for mercury as well as other hazardous air pollutants (HAPS) and went into effect in April 2015. In April 2016, the EPA released the final Supplemental Finding that considers the materiality of costs in determining whether to regulate hazardous air pollutants from power plants in response to a ruling by the U.S. Supreme Court. The 2016 Supplemental Finding determined that HAPS from existing electric generating units should be regulated and that the environmental and health benefits derived from the reduction in emissions of both HAPS and co-benefit pollutants far outweighed the cost of compliance. Industry participants and various state authorities filed petitions with the D.C. Circuit challenging the EPA’s Supplemental Finding.
In May 2020, the EPA finalized a revised Supplemental Finding that reversed the 2016 Supplemental Finding, concluding that it was not “appropriate and necessary” to regulate HAPS from electric generating sources. However, the EPA retained the emission standards and other requirements of MATS. A major coal mining company filed a lawsuit to force the EPA to vacate MATS. We have filed as intervenors to the coal mining company’s suit to challenge the company’s attempt to vacate MATS. In addition, we have joined a challenge against the EPA’s revised Supplemental Finding in the D.C. Circuit Court. We cannot predict the outcome of this matter.
Climate Change
CO2 Regulation under the Clean Air Act-In June 2019, the EPA issued its final ACE rule as a replacement for the repealed Clean Power Plan, a GHG emission regulation for existing power plants. The ACE rule narrowly defines the “best system of emissions reductions” (BSER) as heat improvements to be applied only to an individual unit, excluding other potential mechanisms to address climate change. In September 2019, a coalition of power companies, including PSEG, filed a Petition for Review of the ACE rule with the D.C. Circuit challenging the EPA’s narrow interpretation of BSER. In January 2021, the D.C. Circuit vacated the ACE rule and remanded the rulemaking to the EPA for further consideration. We cannot predict the outcome of this matter or estimate its impact on our business or results of operations.
RGGI-Certain northeastern states (RGGI States) participate in the RGGI and have state-specific rules in place to enable the RGGI regulatory mandate in each state to cap and reduce CO2 emissions. Generating plants operating in RGGI states that emit CO2 will have to procure credits for each ton that they emit. The post-2020 program cap on regional CO2 emissions for RGGI requires a decline in CO2 emissions in 2021 and each year thereafter, resulting in a 30% reduction in the CO2 emissions cap by 2030.
In June 2019, the NJDEP issued two rules that began New Jersey’s re-entry into RGGI. The first rule established New Jersey’s initial cap on GHG emissions of 18 million tons in 2020. This rule follows the RGGI model rule with a cap that will decline three percent annually through 2030 to a final cap of 11.5 million tons. The second rule established the framework for how credits will be allocated among the New Jersey Economic Development Authority , the BPU and the NJDEP. In April 2020, the state issued a final three-year Strategic Funding Plan that determines how quarterly RGGI credits are to be allocated. New Jersey facilities became subject to RGGI on January 1, 2020. With New Jersey’s re-entry into RGGI, we have generation facilities in four of the RGGI States, specifically New Jersey, New York, Maryland and Connecticut.
New Jersey adopted the Global Warming Response Act in 2007, which calls for stabilizing its GHG emissions to 1990 levels by 2020, followed by a further reduction of greenhouse emissions to 80% below 2006 levels by 2050. To reach this goal, the NJDEP, the BPU, other state agencies and stakeholders are required to evaluate methods to meet and exceed the emission reduction targets, taking into account their economic benefits and costs.
New Jersey Protecting Against Climate Threats (NJ PACT)-In response to a New Jersey Executive Order, the NJDEP has undertaken a regulatory reform effort that is designed to modernize environmental laws, referred to as New Jersey Protecting Against Climate Threats (NJ PACT). When implemented, NJ PACT is expected to result in changes to existing environmental regulation, modernizing air quality and environmental land use regulations that will enable governments, businesses and residents to effectively respond to current climate threats and reduce future climate damages. We continue to assess the potential impact of the NJ PACT, which could have cost implications for construction of new or upgrades to existing utility infrastructure and upgrades of our fossil generation facilities. Such expenditures could materially affect the continued economic viability and/or cost to construct one or more such facilities.
Water Pollution Control
The Federal Water Pollution Control Act (FWPCA) prohibits the discharge of pollutants to U.S. waters from point sources, except pursuant to a National Pollutant Discharge Elimination System (NPDES) permit issued by the EPA or by a state under a federally authorized state program. The FWPCA authorizes the imposition of technology-based and water quality-based
effluent limits to regulate the discharge of pollutants into surface waters and ground waters. The EPA has delegated authority to a number of state agencies, including those in New Jersey, New York and Connecticut, to administer the NPDES program through state action. We also have ownership interests in facilities in other jurisdictions that have their own laws and implement regulations to control discharges to their surface waters and ground waters that directly govern our facilities in those jurisdictions.
The EPA’s Clean Water Act (CWA) Section 316(b) rule establishes requirements for the regulation of cooling water intakes at existing power plants and industrial facilities with a design flow of more than two million gallons of water per day. The EPA requires that the NPDES permits be renewed every five years and that each state Permitting Director manage renewal permits for its respective power generation facilities on a case by case basis. The NJDEP manages the permits under the New Jersey Pollutant Discharge Elimination System program. Connecticut and New York also have permits to manage their respective pollutant discharge elimination system programs.
Hazardous Substance Liability
The production and delivery of electricity and the distribution and manufacture of gas result in various by-products and substances classified by federal and state regulations as hazardous. These regulations may impose liability for damages to the environment from hazardous substances, including obligations to conduct environmental remediation of discharged hazardous substances and monetary payments, regardless of the absence of fault, any contractual agreements between private parties, and the absence of any prohibitions against the activity when it occurred, as well as compensation for injuries to natural resources. Our historic operations and the operations of hundreds of other companies along the Passaic and Hackensack Rivers are alleged by federal and state agencies to have discharged substantial contamination into the Passaic River/Newark Bay Complex. The EPA is also evaluating the Hackensack River, a tributary to Newark Bay, for inclusion in the Superfund program. We no longer manufacture gas.
Site Remediation-The Federal Comprehensive Environmental Response, Compensation and Liability Act of 1980 (CERCLA) and the New Jersey Spill Compensation and Control Act (Spill Act) require the remediation of discharged hazardous substances and authorize the EPA, the NJDEP and private parties to commence lawsuits to compel clean-ups or reimbursement for such remediation. The clean-ups can be more complicated and costly when the hazardous substances are in or under a body of water.
Natural Resource Damages-CERCLA and the Spill Act authorize the assessment of damages against persons who have discharged a hazardous substance, causing an injury to natural resources. Pursuant to the Spill Act, the NJDEP requires persons conducting remediation to address injuries to natural resources through restoration or damages. The NJDEP adopted regulations concerning site investigation and remediation that require an ecological evaluation of potential damages to natural resources in connection with an environmental investigation of contaminated sites.
Fuel and Waste Disposal
Nuclear Fuel Disposal-The federal government has entered into contracts with the operators of nuclear power plants for transportation and ultimate disposal of spent nuclear fuel. Under the Nuclear Waste Policy Act of 1982 (NWPA), nuclear plant owners are required to contribute to a Nuclear Waste Fund to pay for this service. Since May 2014, the United States Department of Energy (DOE) reduced the nuclear waste fee to zero. No assurances can be given that this fee will not be increased in the future. The NWPA allows spent nuclear fuel generated in any reactor to be stored in reactor facility storage pools or in Independent Spent Fuel Storage Installations located at reactors or away from reactor sites.
We have on-site storage facilities that are expected to satisfy the storage needs of Salem 1, Salem 2, Hope Creek, Peach Bottom 2 and Peach Bottom 3 through the end of their operating licenses.
Low-Level Radioactive Waste-As a by-product of their operations, nuclear generation units produce low-level radioactive waste. Such waste includes paper, plastics, protective clothing, water purification materials and other materials. These waste materials are accumulated on site and disposed of at licensed permanent disposal facilities. New Jersey, Connecticut and South Carolina have formed the Atlantic Compact, which gives New Jersey nuclear generators continued access to the Barnwell waste disposal facility which is owned by South Carolina. We believe that the Atlantic Compact will provide for adequate low-level radioactive waste disposal for Salem and Hope Creek through the end of their current licenses including full decommissioning, although no assurances can be given. Low-Level Radioactive Waste is periodically being shipped to the Barnwell site from Salem and Hope Creek. Additionally, there are on-site storage facilities for Salem, Hope Creek and Peach Bottom, which we believe have the capacity for at least five years of temporary storage for each facility.
INFORMATION ABOUT OUR EXECUTIVE OFFICERS (PSEG)
Name Age as of
December 31,
2020 Office Effective Date
First Elected to
Present Position
Ralph Izzo 63 Chairman of the Board (COB), President and
Chief Executive Officer (CEO) - PSEG April 2007 to present
COB and CEO - PSE&G April 2007 to present
COB and CEO - PSEG Power April 2007 to present
COB and CEO - Energy Holdings April 2007 to present
COB and CEO - Services January 2010 to present
Daniel J. Cregg 57 Executive Vice President (EVP) and Chief Financial Officer (CFO) - PSEG October 2015 to present
EVP and CFO - PSE&G October 2015 to present
EVP and CFO - PSEG Power October 2015 to present
Ralph A. LaRossa 57 COB - PSEG Long Island LLC December 2020 to present
Chief Operating Officer (COO) - PSEG January 2020 to present
President and COO - PSEG Power October 2017 to present
President and COO - PSE&G October 2006 to October 2017
COB - PSEG Long Island LLC October 2013 to October 2017
David M. Daly 59 President - PSE&G October 2017 to present
President and COO of PSEG Utilities and Clean Energy Ventures - Services; President - PSE&G January 2020 to December 2020
COB - PSEG Long Island LLC October 2017 to December 2020
COO - PSE&G October 2017 to December 2019
President and COO - PSEG Long Island LLC October 2013 to October 2017
Derek M. DiRisio 56 President - Services August 2014 to present
Tamara L. Linde 56 EVP and General Counsel - PSEG July 2014 to present
EVP and General Counsel - PSE&G July 2014 to present
EVP and General Counsel - PSEG Power July 2014 to present
Rose M. Chernick 57 VP and Controller - PSEG March 2019 to present
VP and Controller - PSE&G March 2019 to present
VP and Controller - PSEG Power March 2019 to present
VP-Finance, Corporate Strategy and Planning - Services November 2017 to March 2019
VP-Finance, Holdings and Corporate Strategy and Planning - Services October 2015 to November 2017

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ITEM 1A. RISK FACTORS
ITEM 1A. RISK FACTORS
The following factors should be considered when reviewing our business. These factors could have a material adverse impact on our business, prospects, financial position, results of operations or cash flows and could cause results to differ materially from those expressed elsewhere in this report.
GENERAL OPERATIONAL AND FINANCIAL RISKS
Inability to successfully develop, obtain regulatory approval for, or construct generation, transmission and distribution projects could adversely impact our businesses.
Our business plan calls for extensive investment in capital improvements and additions, including the construction and/or acquisition of T&D facilities and generation units; and modernizing existing infrastructure pursuant to investment programs entitled to current recovery. Currently, we have several significant projects underway or being contemplated.
The successful construction and development of these projects will depend, in part, on our ability to:
•obtain necessary governmental and regulatory approvals;
•obtain environmental permits and approvals;
•obtain community support for such projects to avoid delays in the receipt of permits and approvals from regulatory authorities;
•complete such projects within budgets and on commercially reasonable terms and conditions;
•obtain any necessary debt financing on acceptable terms and/or necessary governmental financial incentives;
•ensure that contracting parties, including suppliers, perform under their contracts in a timely and cost effective manner; and
•at PSE&G, recover the related costs through rates.
Any delays, cost escalations or otherwise unsuccessful construction and development could materially affect our financial position, results of operations and cash flows. Modifications to existing facilities may require us to install the best available control technology or to achieve the lowest achievable emission rates required by then-current regulations, which would likely result in substantial additional capital expenditures.
In addition, the successful operation of new or upgraded generation facilities or transmission or distribution projects is subject to risks relating to supply interruptions; work stoppages and labor disputes; weather interferences; unforeseen engineering and environmental problems, including those related to climate change; and the other risks described herein. Any of these risks could cause our return on these investments to be lower than expected or they could cause these facilities to operate below expected capacity or availability levels, which would adversely impact our financial condition and results of operations through lost revenue, increased expenses, higher maintenance costs and penalties.
Lack of growth or slower growth in the number of customers, or a decline in customer demand, which may not be fully addressed by our recently approved CIP, could adversely impact our financial condition, results of operations and cash flows.
Our CIP, which was recently approved by the BPU as part of our CEF-EE program, reduces the impact on our distribution revenues from changes in sales volumes and demand for most customers. The CIP, which is calculated annually, provides for a true-up to our current period revenue as compared to revenue thresholds established in our most recent distribution base rate proceeding. Recovery under the CIP is subject to certain limitations, including an actual versus allowed ROE test and ceilings on customer rate increases. The CIP does not address changes in the number of customers.
Growth in customer accounts and growth of customer usage each directly influence the demand for electricity and the need for additional transmission and distribution facilities. Customer growth and customer usage may be affected by a number of factors, including:
•the impacts of economic downturns, including increased unemployment and less demand from C&I customers;
•regulatory initiatives to reduce energy consumption or that favor certain fuel types;
•mandated energy efficiency measures;
•DSM tools;
•technological advances; and
•a shift in the composition of our customer base from C&I customers to residential customers.
Some or all of these factors could result in a lack of growth or decline in customer demand for electricity and may prevent us from fully realizing the benefits from significant capital investments and expenditures, which could have a material adverse effect on our financial position, results of operations and cash flows.
We may be adversely affected by equipment failures, accidents, severe weather events, acts of war or terrorism or other incidents, including pandemics such as the ongoing coronavirus pandemic, that impact our ability to provide safe and reliable service to our customers and remain competitive and could result in substantial financial losses.
The success of our businesses is dependent on our ability to continue providing safe and reliable service to our customers while minimizing service disruptions. We are exposed to the risk of equipment failures, accidents, severe weather events, acts of war or terrorism or other incidents which could result in damage to or destruction of our facilities or damage to persons or property.
We are also exposed to the risk of pandemics, such as the ongoing coronavirus pandemic, which could result in service disruptions and delay or otherwise impair our ability to timely provide service to our customers or complete our investment projects.
These events could result in increased political, economic and financial and insurance market instability and volatility in power and fuel markets, which could materially adversely affect our business and results of operations, including our ability to access capital on terms and conditions acceptable to us.
In addition, the physical risks of severe weather events, such as experienced from Superstorm Sandy and more recently Tropical Storm Isaias, and of climate change, changes in sea level, temperature and precipitation patterns and other related phenomena have further exacerbated these risks. Such issues experienced at our facilities, or by others in our industry, could adversely impact our revenues; increase costs to repair and maintain our systems; subject us to potential litigation and/or damage claims, fines or penalties; and increase the level of oversight of our utility and generation operations and infrastructure through investigations or through the imposition of additional regulatory or legislative requirements. Such actions could adversely affect our costs, competitiveness and future investments, which could be material to our financial position, results of operations and cash flow. For our T&D business, the cost of storm restoration efforts may not be fully recoverable through the regulatory process. In addition, the inability to restore power to our customers on a timely basis could also materially damage our reputation.
Any inability to recover the carrying amount of our long-lived assets could result in future impairment charges which could have a material adverse impact on our financial condition and results of operations.
Long-lived assets represent approximately 75%, 82% and 65% of the total assets of PSEG, PSE&G and PSEG Power, respectively, as of December 31, 2020. Management evaluates long-lived assets for impairment whenever events or changes in circumstances, such as significant adverse changes in regulation, business climate or market conditions, including prolonged periods of adverse commodity and capacity prices, could potentially indicate an asset’s or group of assets’ carrying amount may not be recoverable. Significant reductions in our expected revenues or cash flows for an extended period of time resulting from such events could result in future asset impairment charges, which could have a material adverse impact on our financial condition and results of operations.
Inability to maintain sufficient liquidity in the amounts and at the times needed or access sufficient capital at reasonable rates or on commercially reasonable terms could adversely impact our business.
Funding for our investments in capital improvement and additions, scheduled payments of principal and interest on our existing indebtedness and the extension and refinancing of such indebtedness has been provided primarily by internally-generated cash flow and external financings. We have significant capital requirements and depend on our ability to generate cash in the future from our operations and continued access to capital and credit markets to efficiently fund our cash flow needs. Our ability to generate cash flow is dependent upon, among other things, industry conditions and general economic, financial, competitive, legislative, regulatory and other factors. The ability to arrange financing and the costs of such financing depend on numerous factors including, among other things.
•general economic and capital market conditions;
•the availability of credit from banks and other financial institutions;
•tax, regulatory and securities law developments;
•for PSE&G, our ability to obtain necessary regulatory approvals for the incurrence of additional indebtedness;
•investor confidence in us and our industry;
•our current level of indebtedness and compliance with covenants in our debt agreements;
•the success of current projects and the quality of new projects;
•our current and future capital structure;
•our financial performance and the continued reliable operation of our business; and
•maintenance of our investment grade credit ratings.
Market disruptions, such as economic downturns experienced in the U.S. and abroad, the bankruptcy of an unrelated energy company or a systemically important financial institution, changes in market prices for electricity and gas, and actual or threatened acts of war or terrorist attacks, may increase our cost of borrowing or adversely affect our ability to access capital. As a result, no assurance can be given that we will be successful in obtaining financing for projects and investments, to extend or refinance maturing debt or for our other cash flow needs on acceptable terms or at all, which could materially adversely impact our financial position, results of operations and future growth.
In addition, if PSEG Power were to lose its investment grade credit rating from S&P or Moody’s, it would be required under certain agreements to provide a significant amount of additional collateral in the form of letters of credit or cash, which would have a material adverse effect on our liquidity and cash flows.
Cybersecurity attacks or intrusions could adversely impact our businesses.
Cybersecurity threats to the U.S. energy market infrastructure are increasing in sophistication, magnitude and frequency, particularly since the COVID-19 pandemic and the resulting shift to virtual operations began. We rely on information technology systems that utilize sophisticated digital systems and network infrastructure to operate our generation and T&D systems. We also store sensitive data, intellectual property and proprietary or personally identifiable information regarding our business, employees, shareholders, customers and vendors on our systems and conduct power marketing and hedging activities. In addition, the operation of our business is dependent upon the information technology systems of third parties, including our vendors, regulators, RTOs and ISOs, among others. Our and third-party information technology systems and products may be vulnerable to cybersecurity attacks involving fraud, malice or oversight on the part of our employees, other insiders or third parties, whether domestic or foreign sources. A cybersecurity attack may also leverage such information technology to cause disruptions at a third party. Cybersecurity impacts to our operations include:
•disruption of the operation of our assets, the fuel supply chain and the power grid,
•theft of confidential company, employee, shareholder, vendor or customer information, which may cause us to be in breach of certain covenants and contractual obligations,
•general business system and process interruption or compromise, including preventing us from servicing our customers, collecting revenues or the ability to record, process and/or report financial information correctly, and
•breaches of vendors’ infrastructures where our confidential information is stored.
We and our third-party vendors have been and likely will continue to be subject to attempted cybersecurity attacks. While there has been no material impact on our business or operations from these attempted attacks, if a significant cybersecurity event or breach should occur within our company or with one of our material vendors, we could be exposed to significant loss of revenue, material repair costs to intellectual and physical property, significant fines and penalties for non-compliance with existing laws and regulations, significant litigation costs, increased costs to finance our businesses, damage to our reputation and loss of confidence from our customers, regulators, investors, vendors and employees. Similarly, a significant cybersecurity event or breach experienced by a competitor, regulatory authority, RTO, ISO, or vendor could also materially impact our business and results of operations via enhanced legal and regulatory requirements. For a discussion of state and federal cybersecurity regulatory requirements and information regarding our cybersecurity program, see Item 1. Business-Regulatory Issues.
Our financial condition and results of operations could be adversely affected by the ongoing coronavirus pandemic.
In response to the ongoing global coronavirus pandemic, we have implemented a comprehensive set of actions to help our customers, communities and employees, and will continue to closely monitor developments and adjust as needed to ensure reliable service while protecting the safety and health of our workforce and the communities we serve.
PSE&G, PSEG Power and PSEG LI are providing essential services during this national emergency related to the coronavirus pandemic. The pandemic’s potential impact will depend on a number of factors outside of our control, including the duration and severity of the outbreak as well as third-party actions taken to contain its spread and mitigate its public health effects. We currently cannot estimate the potential impact the ongoing coronavirus pandemic may have on our business, results of operations, financial condition, liquidity and cash flows. However a prolonged outbreak, including the long-term impact it may have on the economy, which could extend beyond the duration of the pandemic, could affect, among other things:
•the timing of our planned capital programs, including the ability to obtain necessary permits and approvals for our capital programs;
•PSE&G’s residential and C&I customer payment patterns, in part as residential customer service non-safety related service disconnections for non-payment have been temporarily suspended, resulting in adverse impacts to accounts receivable and bad debt expense;
•the recovery of incremental costs incurred related to the pandemic, including higher gas bad debts;
•decreased aggregate demand for generation and decreased C&I demand for PSE&G’s electric and gas service;
•the availability of capital markets and credit from banks and other financial institutions to fund our operations and capital programs and the cost of borrowing and available terms;
•the availability and productivity of skilled workers and contractors to operate our facilities;
•the ability of our counterparties to meet their contractual obligations to us;
•the potential for assessment of impairment of our long-lived assets;
•our financial assets recorded at fair value, including the impact on Net Income from adjustments to fair value of investments in our pension and Nuclear Decommissioning Trust (NDT) Fund, and potential increases in the related funding requirements; and
•the availability of materials and supplies due to supply chain interruptions.
We continue to implement strong physical and cybersecurity measures to ensure that our systems remain functional in order to both serve our operational needs with a remote workforce and ensure uninterrupted service to our customers. Any failure or breach of these systems would have a material impact on our business and results of operations.
Covenants in our debt instruments may adversely affect our operations.
PSEG’s, PSE&G’s and PSEG Power’s debt instruments contain events of default customary for financings of their type, including cross accelerations to other debt of that entity and, in the case of PSEG’s and PSEG Power’s bank credit agreements, certain change of control events. PSEG Power’s bank credit agreements and outstanding notes also contain limitations on the incurrence of subsidiary debt and liens and certain of PSEG Power’s outstanding notes require PSEG Power to repurchase such notes upon certain change of control events. Our ability to comply with these covenants may be affected by events beyond our control. If we fail to comply with the covenants and are unable to obtain a waiver or amendment, or a default exists and is continuing under such debt, the lenders or the holders or trustee of such debt, as applicable, could give notice and declare outstanding borrowings and other obligations under such debt immediately due and payable. We may not be able to obtain waivers, amendments or alternative financing, or if obtainable, it could be on terms that are not acceptable to us. Any of these events could adversely impact our financial condition, results of operations and cash flows.
Financial market performance directly affects the asset values of our NDT Fund and defined benefit plan trust funds. Market performance and other factors could decrease the value of trust assets and could result in the need for significant additional funding.
The performance of the financial markets will affect the value of the assets that are held in trust to satisfy our future obligations under our defined benefit plans and to decommission our nuclear generating plants. A decline in the market value of our NDT Fund could increase PSEG Power’s funding requirements to decommission its nuclear plants. A decline in the market value of the defined benefit plan trust funds could increase our pension plan funding requirements. The market value of our trusts could be negatively impacted by decreases in the rate of return on trust assets, decreased interest rates used to measure the required minimum funding levels and future government regulation. Additional funding requirements for our defined benefit plans could be caused by changes in required or voluntary contributions, an increase in the number of employees becoming eligible to retire and changes in life expectancy assumptions. Increased costs could also lead to additional funding requirements for our decommissioning trust. Failure to adequately manage our investments in our NDT Fund and defined benefit plan trusts could result in the need for us to make significant cash contributions in the future to maintain our funding at sufficient levels, which would negatively impact our results of operations, cash flows and financial position.
RISKS RELATED TO OUR GENERATION BUSINESS
The timeline and ultimate outcome of our exploration of strategic alternatives relating to PSEG Power’s non-nuclear generating fleet is uncertain.
In July 2020, we announced that we were exploring strategic alternatives for PSEG Power’s non-nuclear generating fleet with the intention of accelerating the transformation of our business into a primarily regulated electric and gas utility, with a contracted generation business.
Since the announcement, we have engaged in preparatory activities relating to the potential divestiture of, and begun the marketing processes for these assets. The timeline and ultimate outcome of this process are uncertain. Our ability to divest all or
a portion of these assets, and the applicable terms, conditions and timeline, will depend in large part on the participation of potentially interested parties and the value such parties place on the applicable assets. It is possible that third parties may wish to acquire all, a portion or none of the applicable assets (or engage in another transaction not presently being pursued by us), and the value that such third parties may place on such assets is uncertain. We may encounter difficulty in finding buyers or alternative exit strategies on acceptable terms in a timely manner, or we may dispose of a business at a price or on terms that are less desirable than we had anticipated. The process may further be impacted by, among other things, global and domestic market and economic conditions, conditions generally impacting the fossil and solar generating industries and changes in the regulatory environment or other factors outside of our control. Any transaction agreement that we may enter into will contain various terms and conditions, and it is possible that even if entered into, such transaction may fail to be completed in a timely manner or at all. Any or all of these factors could have a material and adverse impact on our business prospects or results of operations.
PSEG Power’s existing credit agreements and senior notes contain covenants restricting the ability of PSEG Power and its subsidiaries that guarantee its indebtedness from consummating certain mergers, consolidations or asset sales. The disposal of PSEG Power’s non-nuclear generating fleet could, depending on the structure of such transaction, among other factors, trigger a default under one or more of these provisions. For these reasons, or for other reasons, PSEG Power may decide, or be required, to seek amendments or waivers under its credit agreements and may redeem its outstanding senior notes, at a price equal to the principal amount thereof plus a make-whole premium. Whether such amendments, waivers or redemptions will be required will depend on a number of factors, including the structure of any transaction resulting from the strategic review, and any actual redemption price would depend on the applicable treasury rate in effect at such time. It is likewise possible that the ultimate outcome of the process may result in a transaction, or may result in no transaction at all, where the Power notes are not redeemed. If PSEG Power is required to redeem its senior notes, the cost of such redemption would be material.
PSEG Power performed a recoverability test for impairment of certain of its generating assets using a weighted probability cash flow analysis that considers the likelihood of a potential sale or disposition or continuing to operate the assets through their remaining estimated useful lives. As of December 31, 2020, the estimated undiscounted future cash flows of each of the asset groups exceeded the carrying amount and no impairment was identified. However, certain assumptions are subject to change as the potential sales and marketing process progresses. Management expects that a change in the probability of a successful disposition or to a held-for sale classification from a held-for-use classification would have a material adverse impact on PSEG’s and PSEG Power’s future financial results.
Failure to complete, or delays in completing, our proposed investment in the Ocean Wind project could adversely affect our business and prospects. In addition, following the completion of our initial investment in the project, there are numerous operational risks and uncertainties associated with, and we may fail to realize the anticipated strategic and financial benefits of, the Ocean Wind project.
In December 2020, we entered into a definitive agreement with Ørsted North America Inc. (“Ørsted”) pursuant to which we agreed to acquire a 25% interest in the 1,100-megawatt Ocean Wind project from Ørsted. The completion of our initial investment in the Ocean Wind project is subject to certain closing conditions, including, among others, approval by the BPU. While we currently anticipate that the investment will close in the first half of 2021, we cannot predict whether any of the required closing conditions will be satisfied or waived in a timely manner or at all.
Following the completion of our initial investment in the Ocean Wind project, our ability to realize the anticipated strategic and financial benefits of the project is subject to a number of risks, challenges and uncertainties, including, among others:
•the risk that we or Ørsted may determine not to proceed with the project at certain milestones in the development of the project, in accordance with the terms of the transaction documents;
•the fact that, subject to certain investment decision milestones, we will be obligated to fund our proportionate share of future capital expenditures in respect of the project, and such future capital expenditures may be greater than expected as a result of, among other things, potential timing delays, cost overruns, labor disputes or unanticipated liabilities in connection with the project;
•the risk that there may be changes to the tax laws, rules and interpretations applicable to the project, including the risk of any reduction, elimination or expiration of government incentives for wind energy or otherwise that may adversely affect the project’s ability to realize certain anticipated tax benefits and, by extension, our ability to realize a satisfactory return on our investment in the project, including in our capacity as a tax equity investor;
•certain limitations on our ability to influence and control strategic decisions related to the project given our status as a minority investor, and the possibility that we and Ørsted may have different views and priorities regarding the development, construction and operation of the project, as well as other risks and uncertainties inherent in joint venture arrangements;
•risks inherent in entering into a new line of business, offshore wind, in which we have not historically operated, and which may expose us to business and operational risks and liabilities that are different from those we have experienced historically and that may be more difficult to manage given our limited operational experience and resources in this area;
•the risk that we may fail to obtain or maintain, on acceptable terms or at all, any required licenses, permits and other regulatory or third party approvals, or may encounter other environmental or regulatory compliance issues, in connection with the project; and
•the risk of catastrophic events, including damage to project equipment, caused by earthquakes, tornadoes, hurricanes, floods, fires, severe weather, explosions and other natural disasters.
If any such risks or other anticipated or unanticipated liabilities were to materialize, the anticipated benefits of the Ocean Wind project may not be fully realized, if at all, and the future performance of the project and our investment therein, as well as our financial condition and results of operations, may be materially and adversely impacted.
Fluctuations in the wholesale power and natural gas markets could negatively affect our financial condition, results of operations and cash flows.
In the markets where we operate, natural gas prices have a major impact on the price that generators receive for their output. Over the past several years, wholesale prices for natural gas have remained well below the peak levels experienced in 2008, in part due to increased shale gas production as extraction technology has improved. Lower gas prices have resulted in lower electricity prices, which have reduced our margins as nuclear generation costs have not declined similarly.
We may be unable to obtain an adequate fuel supply in the future.
We obtain substantially all of our physical natural gas and nuclear fuel supply from third parties pursuant to arrangements that vary in term, pricing structure, firmness and delivery flexibility. Our fuel supply arrangements must be coordinated with transportation agreements, balancing agreements, storage services and other contracts to ensure that the natural gas and nuclear fuel are delivered to our power plants at the times, in the quantities and otherwise in a manner that meets the needs of our generation portfolio and our customers. We must also comply with laws and regulations governing the transportation of such fuels.
We are exposed to increases in the price of natural gas and nuclear fuel, and it is possible that sufficient supplies to operate our generating facilities profitably may not continue to be available to us. Significant changes in the price of natural gas and nuclear fuel could affect our future results and impact our liquidity needs. In addition, we face risks with regard to the delivery to, and the use of natural gas and nuclear fuel by, our power plants including the following:
•transportation may be unavailable if pipeline infrastructure is damaged or disabled;
•pipeline tariff changes may adversely affect our ability to, or cost to, deliver such fuels;
•creditworthiness of third-party suppliers, defaults by third-party suppliers on supply obligations and our ability to replace supplies currently under contract may delay or prevent timely delivery;
•market liquidity for physical supplies of such fuels or availability of related services (e.g. storage) may be insufficient or available only at prices that are not acceptable to us;
•variation in the quality of such fuels may adversely affect our power plant operations;
•legislative or regulatory actions or requirements, including those related to pipeline integrity inspections, may increase the cost of such fuels;
•fuel supplies diverted to residential heating may limit the availability of such fuels for our power plants; and
•the loss of critical infrastructure, acts of war or terrorist attacks (including cybersecurity breaches) or catastrophic events such as fires, earthquakes, explosions, floods, severe storms or other similar occurrences could impede the delivery of such fuels.
Our nuclear units have a diversified portfolio of contracts and inventory that provide a substantial portion of our fuel raw material needs over the next several years. However, each of our nuclear units has contracted with a single fuel fabrication services provider, and transitioning to an alternative provider could take an extended period of time. Certain of our other generation facilities also require fuel or other services that may only be available from one or a limited number of suppliers. The availability and price of this fuel may vary due to supplier financial or operational disruptions, transportation disruptions and force majeure. At times, such fuel may not be available at any price, or we may not be able to transport it to our facilities on a timely basis. In this case, we may not be able to run those facilities even if it would be profitable. If we had sold forward the
power from such a facility, we could be required to supply or purchase power from alternate sources, perhaps at a loss. This could have a material adverse impact on our business, the financial results of specific plants and on our results of operations.
Although our fuel contract portfolio provides a degree of hedging against these market risks, such hedging may not be effective and future increases in our fuel costs could materially and adversely affect our liquidity, financial condition and results of operations. While our generation runs on a mix of fuels, primarily natural gas and nuclear fuel, an increase in the cost of any particular fuel ultimately used could impact our results of operations.
Operation of our generating stations are subject to market risks that are beyond our control.
Generation output will either be used to satisfy wholesale contract requirements or other bilateral contracts or be sold into competitive power markets. Participants in the competitive power markets are not guaranteed any specified rate of return on their capital investments. Generation revenues and results of operations are dependent upon prevailing market prices for energy, capacity, ancillary services and fuel supply in the markets served. Changes in prevailing market prices could have a material adverse effect on our financial condition and results of operations.
Factors that may cause market price fluctuations include:
•increases and decreases in generation capacity, including the addition of new supplies of power as a result of the development of new power plants, expansion of existing power plants or additional transmission capacity;
•power transmission or fuel transportation capacity constraints or inefficiencies;
•power supply disruptions, including power plant outages and transmission disruptions;
•climate change and weather conditions, particularly unusually mild summers or warm winters in our market areas;
•seasonal fluctuations;
•economic and political conditions that could negatively impact the demand for power;
•changes in the supply of, and demand for, energy commodities;
•development of new fuels or new technologies for the production or storage of power;
•federal and state regulations and actions of the ISOs; and
•federal and state power, market and environmental regulation and legislation, including financial incentives for new renewable energy generation capacity that could lead to oversupply.
Our generation business frequently involves the establishment of forward sale positions in the wholesale energy markets on long-term and short-term bases. To the extent that we have produced or purchased energy in excess of our contracted obligations, a reduction in market prices could reduce profitability. Conversely, to the extent that we have contracted obligations in excess of energy we have produced or purchased, an increase in market prices could reduce profitability. If the strategy we utilize to hedge our exposure to these various risks or if our internal policies and procedures designed to monitor the exposure to these various risks are not effective, we could incur material losses. Our market positions can also be adversely affected by the level of volatility in the energy markets that, in turn, depends on various factors, including weather in various geographical areas, short-term supply and demand imbalances, customer migration and pricing differentials at various geographic locations. These risks cannot be predicted with certainty.
Increases in market prices also affect our ability to hedge generation output and fuel requirements as the obligation to post margin increases with increasing prices.
The introduction or expansion of technologies related to energy generation, distribution and consumption and changes in customer usage patterns could adversely impact us.
The power generation business has seen a substantial change in the technologies used to produce power. Newer generation facilities are often more efficient than aging facilities, which may put some of these older facilities at a competitive disadvantage to the extent newer facilities are able to consume the same or less fuel to achieve a higher level of generation output. Federal and state incentives for the development and production of renewable sources of power have facilitated the penetration of competing technologies, such as wind, solar, and commercial-sized power storage. Additionally, the development of DSM and energy efficiency programs can impact demand requirements for some of our markets at certain times during the year. The continued development of subsidized, competing power generation technologies and significant development of DSM and energy efficiency programs could alter the market and price structure for power generation and could result in a reduction in load requirements, negatively impacting our financial condition, results of operations and cash flows. Technological advances driven by federal laws mandating new levels of energy efficiency in end-use electric devices or other improvements in, or applications of, technology could also lead to declines in per capita energy consumption.
Advances in distributed generation technologies, such as fuel cells, micro turbines, micro grids, windmills and net-metered solar installations, may reduce the cost of alternative methods of producing electricity to a level that is competitive with that of most central station electric production. Large customers, such as universities and hospitals, continue to explore potential micro grid installation. Certain states, such as Massachusetts and California, are also considering mandating the use of power storage resources to replace uneconomic or retiring generation facilities. Such developments could (i) affect the price of energy, (ii) reduce energy deliveries as customer-owned generation becomes more cost-effective, (iii) require further improvements to our distribution systems to address changing load demands, and (iv) make portions of our transmission and/or distribution facilities obsolete prior to the end of their useful lives. These technologies could also result in further declines in commodity prices or demand for delivered energy.
Some or all of these factors could result in a lack of growth or decline in customer demand for electricity or number of customers, and may cause us to fail to fully realize anticipated benefits from significant capital investments and expenditures, which could have a material adverse effect on our financial position, results of operations and cash flows. These factors could also materially affect our results of operations, cash flows or financial positions through, among other things, reduced operating revenues, increased operating and maintenance expenses, and increased capital expenditures, as well as potential asset impairment charges or accelerated depreciation and decommissioning expenses over shortened remaining asset useful lives.
We are subject to third-party credit risk relating to our sale of generation output and purchase of fuel.
We sell generation output and buy fuel through the execution of bilateral contracts. We also seek to contract in advance for a significant proportion of our anticipated output capacity and fuel needs. These contracts are subject to credit risk, which relates to the ability of our counterparties to meet their contractual obligations to us. Any failure of these counterparties to perform could require PSEG Power to purchase or sell energy or fuel in the wholesale markets at less favorable prices and incur additional losses, which could have a material adverse impact on our results of operations, cash flows and financial position. In the spot markets, we are exposed to the risks of the default sharing mechanisms that exist in those markets, some of which attempt to spread the risk across all participants. Therefore, a default by a third party could increase our costs, which could negatively impact our results of operations and cash flows.
There may be periods when PSEG Power may not be able to meet its commitments under forward sale obligations at a reasonable cost or at all.
A substantial portion of PSEG Power’s base load generation output has been sold forward under fixed price power sales contracts and PSEG Power also sells forward the output from its intermediate and peaking facilities when it deems it commercially advantageous to do so. Our forward sales of energy and capacity assume sustained, acceptable levels of operating performance. This is especially important at our lower-cost facilities. Operations at any of our plants could degrade to the point where the plant has to shut down or operate at less than full capacity. Some issues that could impact the operation of our facilities are:
•breakdown or failure of equipment, information technology, processes or management effectiveness;
•disruptions in the transmission of electricity;
•labor disputes or work stoppages;
•fuel supply interruptions;
•transportation constraints;
•limitations which may be imposed by environmental or other regulatory requirements; and
•operator error, acts of war or terrorist attacks (including cybersecurity breaches) or catastrophic events such as fires, earthquakes, explosions, floods, severe storms or other similar occurrences.
Identifying and correcting any of these issues may require significant time and expense. Depending on the materiality of the issue, we may choose to close a plant rather than incur the expense of restarting it or returning it to full capacity.
Because the obligations under most of these forward sale agreements are not contingent on a unit being available to generate power, PSEG Power is generally required to deliver power to the buyer even in the event of a plant outage, fuel supply disruption or a reduction in the available capacity of the unit. To the extent that PSEG Power does not have sufficient lower cost capacity to meet its commitments under its forward sale obligations, PSEG Power would be required to pay the difference between the market price at the delivery point and the contract price. The amount of such payments could be substantial and could have a material adverse effect on our financial condition, results of operations and cash flows.
In addition, as market prices for energy and fuel fluctuate, our forward energy sale and forward fuel purchase contracts could require us to post substantial additional collateral, thus requiring us to obtain additional sources of liquidity during periods when our ability to do so may be limited.
Certain of our generation facilities rely on transmission facilities that we do not own or control and that may be subject to transmission constraints. Transmission facility owners’ inability to maintain adequate transmission capacity could restrict our ability to deliver wholesale electric power to our customers and we may either incur additional costs or forgo revenues. Conversely, improvements to certain transmission systems could also reduce revenues.
We depend on transmission facilities owned and operated by others to deliver the wholesale power we sell from our generation facilities. If transmission is disrupted or if the transmission capacity infrastructure is inadequate, our ability to sell and deliver wholesale power may be adversely impacted. If a region’s power transmission infrastructure is inadequate, our recovery of wholesale costs and profits may be limited. If restrictive transmission price regulation is imposed, the transmission companies may not have sufficient incentive to invest in transmission infrastructure. We also cannot predict whether transmission facilities will invest in specific markets to accommodate competitive access to those markets.
In addition, in certain of the markets in which we operate, energy transmission congestion may occur and we may be deemed responsible for congestion costs if we schedule delivery of power between congestion zones during times when congestion occurs between the zones. If we were liable for such congestion costs, our financial results could be adversely affected.
Conversely, a portion of our generation is located in load pockets. Investment in transmission systems to reduce or eliminate these load pockets could negatively impact the value or profitability of our existing generation facilities in these areas.
REGULATORY, LEGISLATIVE AND LEGAL RISKS
PSE&G’s revenues, earnings and results of operations are dependent upon state laws and regulations that affect distribution and related activities.
PSE&G is subject to regulation by the BPU. Such regulation affects almost every aspect of its businesses, including its retail rates, and failure to comply with these regulations could have a material adverse impact on PSE&G’s ability to operate its business and could result in fines, penalties or sanctions. The retail rates for electric and gas distribution services are established in a base rate proceeding and remain in effect until a new base rate proceeding is filed and concluded. In addition, our utility has received approval for several clause recovery mechanisms, some of which provide for recovery of costs and earn returns on authorized investments. These clause mechanisms require periodic updates to be reviewed and approved by the BPU and are subject to prudency reviews. Inability to obtain fair or timely recovery of all our costs, including a return of, or on, our investments in rates, could have a material adverse impact on our results of operations and cash flows. In addition, if legislative and regulatory structures were to evolve in such a way that PSE&G’s exclusive rights to serve its regulated customers were eroded, its future earnings could be negatively impacted.
In September 2020, the BPU ordered the commencement of a comprehensive affiliate and management audit of PSE&G. The BPU also conducts periodic combined management/competitive service audits of New Jersey utilities related to affiliate standard requirements, competitive services, cross-subsidization, cost allocation and other issues. A finding by the BPU of non-compliance with these requirements could result in fines, a reduction in PSE&G’s authorized base rate or the disallowance of the recovery of certain costs, which could have a material adverse impact on our business, results of operations and cash flows. For information regarding PSE&G’s current affiliate and management audit, see Item 8. Note 15. Commitments and Contingent Liabilities. In addition, PSE&G procures the supply requirements of its default service BGSS gas customers through a full-requirements contract with PSEG Power. Government officials, legislators and advocacy groups are aware of the affiliation between PSE&G and PSEG Power. In periods of rising utility rates, those officials and advocacy groups may question or challenge costs and transactions incurred by PSE&G with PSEG Power, irrespective of any previous regulatory processes or approvals underlying those transactions. The occurrence of such challenges may subject PSEG Power to a level of scrutiny not faced by other unaffiliated competitors in those markets and could adversely affect retail rates received by PSE&G in an effort to offset any perceived benefit to PSEG Power from the affiliation.
PSE&G’s proposed investment programs may not be fully approved by regulators, which could result in lower than desired service levels to customers, and actual capital investment by PSE&G may be lower than planned, which would cause lower than anticipated rate base.
PSE&G is a regulated public utility that operates and invests in an electric T&D system and a gas distribution system as well as certain regulated clean energy investments, including solar and energy efficiency within New Jersey. PSE&G invests in capital projects to maintain and improve its existing T&D system and to address various public policy goals and meet customer expectations. Transmission projects are subject to review in the FERC-approved PJM transmission expansion process while distribution and clean energy projects are subject to approval by the BPU. We cannot be certain that any proposed project will be approved as requested or at all. If the programs that PSE&G may file from time to time are only approved in part, or not at all, or if the approval fails to allow for the timely recovery of all of PSE&G’s costs, including a return of, or on, its investment, PSE&G will have a lower than anticipated rate base, thus causing its future earnings to be lower than anticipated. If these programs are not approved, that could also adversely affect our service levels for customers. Further, the BPU could take positions to exclude or limit utility participation in certain areas, such as renewable generation, energy efficiency, electric
vehicle infrastructure and energy storage, which would limit our relationship with customers and narrow our future growth prospects.
We are subject to comprehensive federal regulation that affects, or may affect, our businesses.
We are subject to regulation by federal authorities. Such regulation affects almost every aspect of our businesses, including management and operations; the terms and rates of transmission services; investment strategies; the financing of our operations and the payment of dividends. Failure to comply with these regulations could have a material adverse impact on our ability to operate our business and could result in fines, penalties or sanctions.
Recovery of wholesale transmission rates-PSE&G’s wholesale transmission rates are regulated by FERC and are recovered through a FERC-approved formula rate. The revenue requirements are reset each year through this formula.
In 2019 and 2020, FERC issued a series of orders that establish a new ROE policy for reviewing existing transmission ROEs. The methodology uses the DCF model, the CAPM and the risk premium model to determine if an existing base ROE is unjust and unreasonable and, if so, what replacement ROE is appropriate. In addition, ROE complaints have been pending before FERC, the ISO New England Inc. transmission owners and utilities in other jurisdictions. Over the past few years, several companies have negotiated settlements that have resulted in reduced ROEs.
We are engaged in settlement discussions with the BPU Staff and the New Jersey Rate Counsel about the level of PSE&G’s base transmission ROE; however, we cannot predict the outcome of these settlement discussions.
Transmission Policy-FERC Order 1000 has generally opened transmission development to competition from independent developers, allowing such developers to compete with incumbent utilities for the construction and operation of transmission facilities in its service territory. While Order 1000 retains limited carve-outs for certain projects that will continue to default to incumbents for construction responsibility, including immediately needed reliability projects, upgrades to existing transmission facilities, projects cost-allocated to a single transmission zone, and projects being built on existing rights-of-way, increased competition for transmission projects could decrease the value of new investments that would be subject to recovery by PSE&G under its rate base, which could have a material adverse impact on our financial condition and results of operations.
NERC Compliance-NERC, at the direction of FERC, has implemented mandatory NERC Operations and Planning and Critical Infrastructure Protection standards to ensure the reliability of the North American Bulk Electric System, which includes electric transmission and generation systems, and to prevent major system blackouts. NERC Critical Infrastructure Protection standards establish cybersecurity and physical security protections for critical systems and facilities. We have been, and will continue to be, periodically audited by NERC for compliance and are subject to penalties for non-compliance with applicable NERC standards. An audit of PSE&G’s compliance with Critical Infrastructure Protection physical and cybersecurity standards was performed in the fourth quarter of 2018 and again in the third quarter of 2020, the results of which are under review. We cannot determine what actions, if any, NERC or FERC may take. Failure to comply with such standards could result in penalties or increased costs to bring such facilities into compliance. Such penalties and costs, as well as lost revenue from prolonged outages required to bring facilities into compliance with these standards, could materially adversely impact our business, results of operations and cash flows.
MBR Authority and Other Regulatory Approvals-Under FERC regulations, public utilities that wish to sell power at market rates must receive MBR authority before making power sales, and the majority of our businesses operate with such authority. Failure to maintain MBR authorization, or the effects of any severe mitigation measures that may be required if market power was evaluated differently in the future, could have a material adverse effect on our business, financial condition and results of operations.
Oversight by the CFTC relating to derivative transactions-The CFTC has regulatory oversight of the swap and futures markets and options, including energy trading, and licensed futures professionals such as brokers, clearing members and large traders. Changes to regulations or adoption of additional regulations by the CFTC, including any regulations relating to futures and other derivatives or margin for derivatives and increased investigations by the CFTC, could negatively impact PSEG Power’s ability to hedge its portfolio in an efficient, cost-effective manner by, among other things, potentially decreasing liquidity in the forward commodity and derivatives markets or limiting PSEG Power’s ability to utilize non-cash collateral for derivatives transactions.
We may also be required to obtain various other regulatory approvals to, among other things, buy or sell assets, engage in transactions between our public utility and our other subsidiaries, and, in some cases, enter into financing arrangements, issue securities and allow our subsidiaries to pay dividends. Failure to obtain these approvals on a timely basis could materially adversely affect our results of operations and cash flows.
Our New Jersey nuclear plants may not be awarded ZECs in future periods, or the current or subsequent ZEC program periods could be materially adversely modified through legal proceedings, either of which could result in the retirement of all of these nuclear plants.
As more fully described in Item 7. MD&A-Executive Overview of 2020 and Future Outlook, in April 2019, PSEG Power’s
Salem 1, Salem 2 and Hope Creek nuclear plants were awarded ZECs by the BPU. The ZEC payment may be adjusted by the BPU under certain conditions. For instance, the New Jersey Rate Counsel, in written comments filed with the BPU, has advocated for the BPU to offset market benefits resulting from New Jersey’s rejoining the RGGI from the ZEC payment. PSEG intends to vigorously defend against these arguments. Due to its preliminary nature, PSEG cannot predict the outcome of this matter.
The BPU’s decision awarding ZECs has been appealed by the New Jersey Rate Counsel. PSEG cannot predict the outcome of this matter.
In October 2020, PSEG Power filed with the BPU its ZEC applications for Salem 1, Salem 2 and Hope Creek for the three-year eligibility period starting in June 2022.
In the event that (i) the ZEC program is overturned or is otherwise materially adversely modified through legal process, (ii) the amount of ZEC payments that may be awarded or other terms and conditions of the second ZEC eligibility period proposed by the BPU in its final decision differ from those of the current ZEC period; or (iii) any of the Salem 1, Salem 2 and Hope Creek plants is not awarded ZEC payments by the BPU and does not otherwise experience a material financial change, PSEG Power will take all necessary steps to cease to operate all of these plants. Alternatively, if all of the Salem 1, Salem 2 and Hope Creek plants are selected to continue to receive ZEC payments but the financial condition of the plants is materially adversely impacted by changes in commodity prices, FERC’s changes to the capacity market construct (absent sufficient capacity revenues provided under a program approved by the BPU in accordance with a FERC-authorized capacity mechanism), or, in the case of the Salem nuclear plants, decisions by the EPA and state environmental regulators regarding the implementation of Section 316(b) of the CWA and related state regulations, or other factors, PSEG Power will take all necessary steps to cease to operate all of these plants and will incur associated costs and accounting charges. These may include, among other things, one-time impairment charges or accelerated Depreciation and Amortization expense on the remaining carrying value of the plants, potential penalties associated with the early termination of capacity obligations and fuel contracts, accelerated asset retirement costs, severance costs, environmental remediation costs and, in certain circumstances, potential additional funding of the NDT Fund, which would be material to both PSEG and PSEG Power.
We may be adversely affected by changes in energy regulatory policies, including energy and capacity market design rules and developments affecting transmission.
The energy industry continues to be regulated and the rules to which our businesses are subject are always at risk of being changed. Our business has been impacted by established rules that create locational capacity markets in each of PJM, ISO-NE and NYISO. Under these rules, generators located in constrained areas are paid more for their capacity so there is an incentive to locate in those areas where generation capacity is most needed. PJM’s capacity market design rules and ISO-NE’s FCM rules continue to evolve, most recently in response to efforts to integrate public policy initiatives into the wholesale markets. For a discussion of recent changes in energy regulatory policies that may affect our business and results of operations, see Item 7. MD&A-Executive Overview of 2020 and Future Outlook.
Further, some of the market-based mechanisms in which we participate, including BGS auctions, are at times the subject of review or discussion by some of the participants in the New Jersey and federal arenas. We can provide no assurance that these mechanisms will continue to exist in their current form, nor otherwise be modified.
To the extent that additions to the transmission system relieve or reduce congestion in eastern PJM where most of our plants are located, PSEG Power’s capacity and energy revenues could be adversely affected. Moreover, through changes encouraged by FERC to transmission planning processes, or through RTO/ISO initiatives to change their planning processes, more transmission may ultimately be built to facilitate renewable generation or support other public policy initiatives. Any such addition to the transmission system could have a material adverse impact on our financial condition and results of operations.
Our ownership and operation of nuclear power plants involve regulatory risks as well as financial, environmental and health and safety risks.
Approximately half of our total generation output each year is provided by our nuclear fleet. For this reason, we are exposed to risks related to the continued successful operation of our nuclear facilities and issues that may adversely affect the nuclear generation industry. In addition to the risk of retirement discussed below, risks associated with the operation of nuclear facilities include:
Storage and Disposal of Spent Nuclear Fuel-Federal law requires the DOE to provide for the permanent storage of spent nuclear fuel but the DOE has not yet begun accepting spent nuclear fuel. Until a federal site is available, we use on-site storage for spent nuclear fuel, which is reimbursed by the DOE. However, future capital expenditures may be required to increase spent fuel storage capacity at our nuclear facilities. Once a federal site is available, the DOE may impose fees to support a permanent repository. In addition, the on-site storage for spent nuclear fuel may significantly increase the decommissioning costs of our nuclear units.
Regulatory and Legal Risk-We may be required to substantially increase capital expenditures or operating or
decommissioning costs at our nuclear facilities to the extent there is a change in the Atomic Energy Act or the applicable regulations, trade controls or the environmental rules and regulations applicable to nuclear facilities; a modification, suspension or revocation of licenses issued by the NRC; the imposition of civil penalties for failure to comply with the Atomic Energy Act, related regulations, trade controls or the terms and conditions of the licenses for nuclear generating facilities; or the shutdown of one of our nuclear facilities. Any such event could have a material adverse effect on our financial condition or results of operations.
Operational Risk-Operations at any of our nuclear facilities could degrade to the point where an affected unit needs to be shut down or operated at less than full capacity. If this were to happen, identifying and correcting the causes may require significant time and expense. Any significant outages could result in reduced earnings as we would have less electric output to sell.
In addition, if a unit cannot be operated through the end of its current estimated useful life, our results of operations could be adversely affected by increased depreciation rates, impairment charges and accelerated future decommissioning costs.
Nuclear Incident or Accident Risk-Accidents and other unforeseen problems have occurred at nuclear stations, both in the U.S. and elsewhere. The consequences of an accident can be severe and may include loss of life, significant property damage and/or a change in the regulatory climate. We have nuclear units at two sites. It is possible that an accident or other incident at a nuclear generating unit could adversely affect our ability to continue to operate unaffected units located at the same site, which would further affect our financial condition, results of operations and cash flows. An accident or incident at a nuclear unit not owned by us could lead to increased regulation, which could affect our ability to continue to economically operate our units. Any resulting financial impact from a nuclear accident may exceed our resources, including insurance coverages. Further, as a licensed nuclear operator subject to the Price-Anderson Act and a member of a nuclear industry mutual insurance company, PSEG Power is subject to potential retroactive assessments as a result of an industry nuclear incident or retrospective premiums due to adverse industry loss experience and such assessments may be material.
In the event of non-compliance with applicable legislation, regulation and licenses, the NRC may increase regulatory oversight, impose fines, and/or shut down a unit, depending on its assessment of the severity of the non-compliance. If a serious nuclear incident were to occur, our business, reputation, financial condition and results of operations could be materially adversely affected. In each case, the amount and types of insurance available to cover losses that might arise in connection with the operation of our nuclear fleet are limited and may be insufficient to cover any costs we may incur.
Decommissioning-NRC regulations require that licensees of nuclear generating facilities demonstrate reasonable assurance that funds will be available to decommission a nuclear facility at the end of its useful life. PSEG Nuclear has established an NDT Fund to satisfy these obligations. However, forecasting trust fund investment earnings and costs to decommission nuclear generating stations requires significant judgment, and actual results could differ significantly from current estimates. If we determine that it is necessary to retire one of our nuclear generating stations before the end of its useful life, there is a risk that it will no longer meet the NRC minimum funding requirements due to the earlier commencement of decommissioning activities and a shorter time period over which the NDT investments could appreciate in value. A shortfall could require PSEG to post parental guarantees or make additional cash contributions to ensure that the NDT Fund continues to satisfy the NRC minimum funding requirements. As a result, our financial position or cash flows could be significantly adversely affected.
We are subject to numerous federal, state and local environmental laws and regulations that may significantly limit or affect our businesses, adversely impact our business plans or expose us to significant environmental fines and liabilities.
We are subject to extensive federal, state and local environmental laws and regulations regarding air quality, water quality, site remediation, land use, waste disposal, the impact of climate change, natural resource damages and other matters. These laws and regulations affect how we conduct our operations and make capital expenditures. There have been a number of recent changes to existing environmental laws and regulations and this trend may continue. We expect there will be changes to existing environmental laws and regulations, particularly in light of the change in administration following the 2020 U.S. presidential election. Changes in these laws, or violations of laws, could result in significant increases in our compliance costs, capital expenditures to bring our facilities into compliance, operating costs for remediation and clean-up actions, civil penalties or damages from actions brought by third parties for alleged health or property damages. Any such increase in our costs could have a material impact on our financial condition, results of operations and cash flows and could require further economic review to determine whether to continue operations or decommission an affected facility. We may also be unable to successfully recover certain of these cost increases through our existing regulatory rate structures, in the case of PSE&G, or our contracts with our customers, in the case of PSEG Power.
Actions by state and federal government agencies could also result in reduced reliance on natural gas and could potentially result in stranding natural gas assets owned and operated by PSEG Power and PSE&G, which could materially adversely affect our business, financial condition and results of operations.
Environmental laws and regulations have generally become more stringent over time, and this trend is likely to continue. For a further discussion of environmental laws and regulations impacting our business, results of operations and financial condition,
including the impact of federal and state laws and regulations relating to GHG emissions and remediation of environmental contamination, see Item 1. Environmental Matters and Item 8. Note 15. Commitments and Contingent Liabilities.
We may not receive necessary licenses and permits in a timely manner or at all, which could adversely impact our business and results of operations.
We must periodically apply for licenses and permits from various regulatory authorities, including environmental regulatory authorities, and abide by their respective orders. Delay in obtaining, or failure to obtain and maintain, any permits or approvals, including environmental permits or approvals, or delay in or failure to satisfy any applicable regulatory requirements, could:
•prevent construction of new facilities,
•limit or prevent continued operation of existing facilities,
•limit or prevent the sale of energy from these facilities, or
•result in significant additional costs,
each of which could materially affect our business, financial condition, results of operations and cash flows. In addition, the process of obtaining licenses and permits from regulatory authorities may be delayed or defeated by concerted community opposition and such delay or defeat could have a material effect on our business.

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

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ITEM 2. PROPERTIES
ITEM 2. PROPERTIES
All of our owned physical property is held by our subsidiaries. We believe that we and our subsidiaries maintain adequate insurance coverage against loss or damage to plants and properties, subject to certain exceptions, to the extent such property is usually insured and insurance is available at a reasonable cost. For a discussion of nuclear insurance, see Item 8. Note 15. Commitments and Contingent Liabilities.
PSE&G
Primarily all of PSE&G’s property is located in New Jersey and PSE&G’s First and Refunding Mortgage, which secures the bonds issued thereunder, constitutes a direct first mortgage lien on substantially all of PSE&G’s property. PSE&G’s electric lines and gas mains are located over or under public highways, streets, alleys or lands, except where they are located over or under property owned by PSE&G or occupied by it under easements or other rights. PSE&G deems these easements and other rights to be adequate for the purposes for which they are being used.
Electric Property and Facilities
As of December 31, 2020, PSE&G’s electric T&D system included approximately 25,000 circuit miles, and 860,000 poles, of which 64% are jointly-owned. In addition, PSE&G owns and operates 54 switching stations with an aggregate installed capacity of 38,353 megavolt-amperes (MVA) and 245 substations with an aggregate installed capacity of 8,647 MVA. Four of those substations, having an aggregate installed capacity of 109 MVA are operated on leased property. In addition, PSE&G owns four electric distribution headquarters and five electric sub-headquarters.
Gas Property and Facilities
As of December 31, 2020, PSE&G’s gas system included approximately 18,000 miles of gas mains, 12 gas distribution headquarters, two sub-headquarters, and one meter shop serving all of its gas territory in New Jersey. In addition, PSE&G operates 58 natural gas metering and regulating stations, of which 22 are located on land owned by customers or natural gas pipeline suppliers and are operated under lease, easement or other similar arrangement. In some instances, the pipeline companies own portions of the metering and regulating facilities. PSE&G also owns one liquefied natural gas and three liquid petroleum air gas peaking facilities. The daily gas capacity of these peaking facilities (the maximum daily gas delivery available during the three peak winter months) is approximately 2.5 million therms in the aggregate.
Solar
As of December 31, 2020, PSE&G owned 158 MW dc of installed PV solar capacity throughout New Jersey.
PSEG Power
Generation Facilities
As of December 31, 2020, PSEG Power’s share of installed fossil and nuclear generating capacity is shown in the following
table:
Name Location Total
Capacity
(MW) % Owned Owned
Capacity
(MW) Principal
Fuels
Used
Steam:
Bridgeport Harbor 3 (A) CT 383 100% 383 Coal
New Haven Harbor CT 448 100% 448 Oil/Gas
Total Steam 831 831
Nuclear:
Hope Creek NJ 1,180 100% 1,180 Nuclear
Salem 1 & 2 NJ 2,285 57% 1,311 Nuclear
Peach Bottom 2 & 3 (B) PA 2,549 50% 1,275 Nuclear
Total Nuclear 6,014 3,766
Combined Cycle:
Keys MD 761 100% 761 Gas
Bergen NJ 1,245 100% 1,245 Gas/Oil
Linden NJ 1,300 100% 1,300 Gas/Oil
Sewaren 7 NJ 538 100% 538 Gas/Oil
Bridgeport Harbor 5 CT 484 100% 484 Gas
Bethlehem NY 817 100% 817 Gas
Kalaeloa HI 208 50% 104 Oil
Total Combined Cycle 5,353 5,249
Combustion Turbine:
Essex NJ 81 100% 81 Gas/Oil
Kearny NJ 456 100% 456 Gas/Oil
Burlington NJ 168 100% 168 Gas/Oil
Linden NJ 336 100% 336 Gas/Oil
New Haven Harbor CT 130 100% 130 Gas/Oil
Bridgeport Harbor 4 CT 17 100% 17 Oil
Total Combustion Turbine 1,188 1,188
Total PSEG Power Plants 13,386 11,034
(A)Plan to early retire in 2021.
(B)Operated by Exelon Generation.
As of December 31, 2020, PSEG Power also owned and operated 467 MW dc of PV solar generation facilities in various states.

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ITEM 3. LEGAL PROCEEDINGS
ITEM 3. LEGAL PROCEEDINGS
We are party to various lawsuits and environmental and regulatory matters, including in the ordinary course of business. For information regarding material legal proceedings, see Item 1. Business-Regulatory Issues and Environmental Matters and Item 8. Note 15. Commitments and Contingent Liabilities.

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ITEM 4. MINE SAFETY DISCLOSURE
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
PART II

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ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Our common stock is listed on the New York Stock Exchange, Inc. under the trading symbol “PEG.” As of February 19, 2021, there were 54,220 registered holders.
The following graph shows a comparison of the five-year cumulative return assuming $100 invested on December 31, 2015 in our common stock and the subsequent reinvestment of quarterly dividends, the S&P Composite Stock Price Index, the Dow Jones Utilities Index and the S&P Electric Utilities Index.
2015 2016 2017 2018 2019 2020
PSEG $ 100.00 $ 117.78 $ 143.42 $ 150.12 $ 175.77 $ 179.96
S&P 500 $ 100.00 $ 111.95 $ 136.38 $ 130.39 $ 171.44 $ 202.96
DJ Utilities $ 100.00 $ 118.18 $ 133.95 $ 136.61 $ 173.90 $ 176.83
S&P Utilities $ 100.00 $ 116.29 $ 130.36 $ 135.72 $ 171.48 $ 172.38
On February 16, 2021, our Board of Directors approved a $0.51 per share common stock dividend for the first quarter of 2021. This reflects an indicative annual dividend rate of $2.04 per share. We expect to continue to pay cash dividends on our common stock; however, the declaration and payment of future dividends to holders of our common stock will be at the discretion of the Board of Directors and will depend upon many factors, including our financial condition, earnings, capital requirements of our businesses, alternate investment opportunities, legal requirements, regulatory constraints, industry practice and other factors that the Board of Directors deems relevant.
In December 2020, we entered into a share repurchase plan that complies with Rule 10b5-1 of the Securities Exchange Act of 1934, as amended, solely with respect to the repurchase of shares to satisfy obligations under equity compensation awards that are expected to be issued in 2021 and the repurchase of shares to satisfy purchases by employees under the Employee Stock Purchase Plan during 2021. There were no common share repurchases in the open market during the fourth quarter of 2020.
The following table indicates the securities authorized for issuance under equity compensation plans as of December 31, 2020:
Plan Category Number of Securities
to be Issued upon
Exercise of
Outstanding Options,
Warrants and Rights (a) Weighted-Average
Exercise Price of
Outstanding
Options, Warrants
and Rights (b) Number of Securities
Remaining Available
for Future Issuance
under Equity
Compensation Plans (excluding securities reflected in column (a)) (c)
Equity Compensation Plans Approved by Security Holders - $ - 15,279,588
Equity Compensation Plans Not Approved by Security Holders - - -
Total - $ - 15,279,588
The number of shares available for future issuance includes amounts remaining under our Amended and Restated 2004 Long-Term Incentive Plan (LTIP), 2007 Equity Compensation Plan for Outside Directors and Employee Stock Purchase Plan and reflect a reduction for non-vested restricted stock units and performance share units (PSUs) (assumed at target payout), including accrued dividend equivalent units. The number of shares available for future issuance may be increased or decreased depending on actual payouts for the PSUs based on achievement of targets and is also increased by the number of shares that are withheld to satisfy tax withholding obligations relating to any plan awards as well as shares subject to awards that are forfeited, canceled or otherwise terminated without the issuance of shares. For additional discussion of specific plans concerning equity-based compensation, see Item 8. Note 20. Stock Based Compensation.
PSE&G
We own all of the common stock of PSE&G. For additional information regarding PSE&G’s ability to continue to pay dividends, see Item 7. MD&A-Liquidity and Capital Resources.
PSEG Power
We own all of PSEG Power’s outstanding limited liability company membership interests. For additional information regarding PSEG Power’s ability to pay dividends, see Item 7. MD&A-Liquidity and Capital Resources.

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

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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (MD&A)
This combined MD&A is separately filed by Public Service Enterprise Group Incorporated (PSEG), Public Service Electric and Gas Company (PSE&G) and PSEG Power LLC (PSEG Power). Information contained herein relating to any individual company is filed by such company on its own behalf. PSE&G and PSEG Power each make representations only as to itself and make no representations whatsoever as to any other company.
PSEG’s business consists of two reportable segments, our principal direct wholly owned subsidiaries, which are:
•PSE&G-which is a public utility engaged principally in the transmission of electricity and distribution of electricity and natural gas in certain areas of New Jersey. PSE&G is subject to regulation by the New Jersey Board of Public Utilities (BPU) and the Federal Energy Regulatory Commission (FERC). PSE&G also invests in regulated solar generation projects and energy efficiency and related programs in New Jersey, which are regulated by the BPU, and
•PSEG Power-which is a multi-regional energy supply company that integrates the operations of its merchant nuclear and fossil generating assets with its power marketing businesses and fuel supply functions through competitive energy sales in well-developed energy markets primarily in the Northeast and Mid-Atlantic United States through its principal direct wholly owned subsidiaries. In addition, PSEG Power owns and operates solar generation in various states. PSEG Power’s subsidiaries are subject to regulation by FERC, the Nuclear Regulatory Commission (NRC), the Environmental Protection Agency (EPA) and the states in which they operate.
PSEG’s other direct wholly owned subsidiaries are: PSEG Long Island LLC (PSEG LI), which operates the Long Island Power Authority’s (LIPA) transmission and distribution (T&D) system under an Amended and Restated Operations Services Agreement (OSA); PSEG Energy Holdings L.L.C. (Energy Holdings), which earns it revenues from its portfolio of lease investments and holds our investment in offshore wind ventures; and PSEG Services Corporation (Services), which provides certain management, administrative and general services to PSEG and its subsidiaries at cost.
Our business discussion in Item 1. Business provides a review of the regions and markets where we operate and compete, as well as our strategy for conducting our businesses within these markets, focusing on operational excellence, financial strength and making disciplined investments. Our risk factor discussion in Item 1A. Risk Factors provides information about factors that could have a material adverse impact on our businesses. The following discussion provides an overview of the significant events and business developments that have occurred during 2020 and key factors that we expect may drive our future performance. This discussion refers to the Consolidated Financial Statements (Statements) and the related Notes to the Consolidated Financial Statements (Notes). This discussion should be read in conjunction with such Statements and Notes.
For a discussion of 2018 items and year-over-year comparisons of changes in our financial condition and results of operations as of and for the years ended December 31, 2019 and December 31, 2018, see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations in our Annual Report on Form 10-K for the year ended December 31, 2019 (2019 Annual Report) as filed with the Securities and Exchange Commission on February 26, 2020.
EXECUTIVE OVERVIEW OF 2020 AND FUTURE OUTLOOK
We are continuing our transformation into a primarily regulated electric and gas utility that is focused on meeting customer expectations and is aligned with public policy objectives promoting infrastructure investments to modernize and improve reliability and clean energy investments. Our business plan focuses on achieving growth while controlling costs and managing the risks associated with regulatory changes, fluctuating commodity prices and changes in customer demand. In furtherance of these goals, over the past few years, our investments have altered our business mix to reflect a higher percentage of earnings contribution by PSE&G. As announced in July 2020, we continue to explore strategic alternatives for PSEG Power’s non-nuclear generating fleet, which includes more than 6,750 megawatts (MW) of fossil generation located in New Jersey, Connecticut, New York and Maryland as well as the 467 MW dc Solar Source portfolio located in various states. See Item 8. Note 4. Early Plant Retirements/Asset Dispositions for additional information.
PSE&G, PSEG Power and PSEG LI continue to provide essential services during the ongoing coronavirus (COVID-19) pandemic. We have implemented a comprehensive set of enhanced safety actions to help protect our employees, customers and communities, and we will continue to closely monitor developments and adjust as needed to ensure that we provide reliable service while protecting the safety and health of our workforce and the communities we serve. We continue to be guided by the recommendations of health authorities at the federal, state and local levels. Employees who can perform their job duties remotely are doing so. Those employees who must report to a work site are wearing personal protective equipment and practicing physical distancing measures.
The ongoing coronavirus pandemic has not had a material impact on our results of operations, financial condition or cash flows for the year ended December 31, 2020. However, the potential future impact of the pandemic and the associated economic impacts, which could extend beyond the duration of the pandemic, will depend on a number of factors outside of our control, including the duration and severity of the outbreak as well as third-party actions taken to contain its spread and mitigate its public health effects. While we currently cannot estimate the potential impact to our results of operations, financial condition and cash flows, this MD&A includes a discussion of potential effects of a prolonged outbreak.
PSE&G
At PSE&G, our focus is on enhancing reliability and resiliency of our T&D system, meeting customer expectations and supporting public policy objectives by investing capital in T&D infrastructure and clean energy programs. For the five-year period ending December 31, 2025, PSE&G expects to invest between $13 billion to $15 billion, resulting in an expected compound annual rate base growth of 6.5% to 8%. The low end of the range assumes an extension of our Gas System Modernization Program (GSMP) and Clean Energy Future (CEF)-Energy Efficiency (EE) program at their average annual investment levels, as these programs are expected to continue at least at those current rates beyond their currently approved timeframes of 2023 and 2024, respectively. The range is driven by certain unapproved investment programs, including a to-be- filed extension of the Energy Strong (ES) program, which otherwise concludes in 2023, as well as the remaining portion of our CEF proposal (portion of Electric Vehicle (EV) and Energy Storage (ES) programs). See below for a description of the CEF program.
In 2019, we commenced our BPU-approved GSMP II, an expanded, five-year program to invest $1.9 billion beginning in 2019 to replace approximately 875 miles of cast iron and unprotected steel mains in addition to other improvements to the gas system. Approximately $1.6 billion will be recovered through periodic rate roll-ins, with the remaining $300 million to be recovered through a future base rate proceeding. As part of the settlement approved by the BPU, PSE&G agreed to file for a
base rate proceeding no later than December 2023, to maintain a base level of gas distribution capital expenditures of $155 million per year and to achieve certain leakage reduction targets. As of December 31, 2020, we had installed 528 miles of cast iron and unprotected steel mains at an investment of $800 million.
Also in 2019, the BPU approved our ES II Program, an $842 million program to harden, modernize and improve the resiliency of our electric and gas distribution systems. This program began in the fourth quarter of 2019 and is expected to be completed by the end of 2023. Approximately $692 million of the program will be recovered through periodic rate recovery filings, with the balance to be recovered in our next distribution base rate case. As of December 31, 2020, we had invested $156 million.
In January 2020, New Jersey released its Energy Master Plan (EMP) which, among other things, recognizes the importance of the State’s EE targets and supported EVs, ES, and advanced metering infrastructure (AMI).
In September 2020, PSE&G reached a settlement with all parties in the CEF-EE proceeding, which the BPU approved. The settlement commits $1 billion over a three-year period, with the majority of the investment occurring over a five-year period. Costs will be recovered through annual rate-making, with returns aligned with our most recent base rate case and a ten-year amortization period.
The approval also included a Conservation Incentive Program, a mechanism that will provide for recovery of lost electric and gas variable margin revenues relative to a baseline of the test year in our last base rate case from July 2017 to June 2018. The deferral period for this mechanism is effective in June 2021 for electric and October 2021 for gas. PSE&G will suspend its gas Weather Normalization Charge (WNC) when the gas deferral period begins.
In January 2021, the BPU approved a settlement with PSE&G and other parties in the CEF-Energy Cloud (EC) proceeding. The capital cost of the program, which includes implementation of AMI, is estimated to be approximately $700 million, invested over the next four years.
Also in January 2021, the BPU approved a settlement with PSE&G and other parties in the CEF-EV proceeding for a majority of the components of the program. The approved investment under the program is for $166 million, primarily relating to preparatory work to deliver infrastructure to the charging point for three programs: residential smart charging; Level-2 mixed use charging; and direct current fast charging.
All of the capital costs and expenses of the CEF-EC and CEF-EV programs will be recovered in PSE&G’s next base rate case, expected in the second half of 2024. From the start of the program until the commencement of new base rates, the return on and of the capital portion of each of these programs, as well as expenses incurred to implement the CEF-EV program and operating costs and stranded costs associated with the retirement of existing meters under the CEF-EC program, will be included for recovery in those rates. The remaining component of our CEF-EV proposal, the vehicle innovation subprogram, as well as the overall CEF-ES program, are being held in abeyance pending future policy guidance from the BPU.
We also continue to invest in transmission infrastructure in order to (i) maintain and enhance system integrity and grid reliability, grid security and safety, (ii) address an aging transmission infrastructure, (iii) leverage technology to improve the operation of the system, (iv) reduce transmission constraints, (v) meet growing demand and (vi) meet environmental requirements and standards set by various regulatory bodies. Our planned capital spending for transmission in 2021-2023 is $2.5 billion.
As noted above, PSE&G has been deemed by New Jersey to provide essential services during the ongoing coronavirus pandemic. Our capital programs, including GSMP II, ES II and our transmission infrastructure investments, have not been materially impacted to date. However, a prolonged outbreak and the associated economic impacts, which could extend beyond the duration of the pandemic, could impact our ability to obtain necessary permits and approvals and could lead to shortages of necessary materials, supplies and labor. In addition, a determination by any state or federal regulatory authority that one or all of our projects is non-essential could require us to temporarily halt work. Any delay in our planned capital program could impact our operational performance and could materially impact our results of operations and financial condition through decreased cost recovery.
Further, the ongoing coronavirus pandemic has led many state and federal agencies to implement remote working protocols and divert resources to address the pandemic which, if prolonged, could impact regulatory agencies’ ability to review proposed programs and delay the timing of approvals for matters subject to regulatory approval, including the approval of various clause recovery mechanisms.
PSE&G has experienced a reduction in demand from its commercial and industrial (C&I) customers, partially offset by increases in residential demand, and adverse changes to residential and C&I payment patterns. PSE&G expects these changes to continue during the prolonged coronavirus pandemic. In October 2020, the state formally extended its moratorium on non-safety related service disconnections for non-payment for residential customers through March 15, 2021. During the moratorium, PSE&G has experienced a significant decrease in cash inflow and higher Accounts Receivable aging and an associated increase in bad debt expense, which we expect could extend beyond the duration of the coronavirus pandemic. PSE&G’s electric distribution bad debt expense is recoverable through its Societal Benefits Clause (SBC) mechanism. PSE&G
has deferred its incremental gas distribution bad debt expense as a result of COVID-19 as a Regulatory Asset and will seek recovery of that cost, as well as other net incremental COVID-19 costs, in its next base rate case.
In July 2020, the BPU authorized regulated utilities in New Jersey, including PSE&G, to create a COVID-19-related Regulatory Asset by deferring on their books and records the prudently incurred incremental costs related to COVID-19 beginning on March 9, 2020 through September 30, 2021, or 60 days after the New Jersey governor determines that the Public Health Emergency is no longer in effect, or in the absence of such a determination, 60 days from the time the Public Health Emergency automatically terminates by law, whichever is later. Deferred costs are to be offset by any federal or state assistance that the utility may receive as a direct result of the COVID-19 pandemic. During 2020, PSE&G recorded a Regulatory Asset related to COVID-19 to defer incremental costs of $51 million, which PSE&G believes are recoverable under the BPU order.
While the impact on our results of operations, financial condition and cash flows for the year ended December 31, 2020 has not been material, a prolonged coronavirus pandemic and the associated economic impacts, which could extend beyond the duration of the pandemic, could materially impact cash from operations, Accounts Receivable and bad debt expense.
PSEG Power
In July 2020, we announced that we are exploring strategic alternatives for PSEG Power’s non-nuclear generating fleet with the intention of accelerating the transformation of our business into a primarily regulated electric and gas utility, with a contracted generation business. It is expected to reduce overall business risk and earnings volatility, improve PSEG’s credit profile and is consistent with PSEG’s climate strategy and sustainability efforts, which is to focus on clean energy investments, methane reduction, and zero-carbon generation. PSEG intends to retain ownership of PSEG Power’s existing nuclear fleet. Since the announcement, we have engaged in proprietary activities relating to the potential divestiture of, and begun the marketing processes for these assets and any potential transactions are expected to be completed sometime in 2021. There is no assurance that the strategic review will result in a sale or other disposition of all or any portion of these assets on terms that are favorable to us, or at all. Any transaction would be subject to market conditions and customary closing conditions, including the receipt of all required regulatory approvals.
At PSEG Power, we have sought to achieve operational excellence and manage costs in order to optimize cash flow generation from our fleet in light of low wholesale power and gas prices, environmental considerations and competitive market forces that reward efficiency and reliability. During 2020, our natural gas and nuclear units generated 22.1 and 30.8 terawatt hours and operated at a capacity factor of 48.3% and 90.3%, respectively. Our commitments for load, such as basic generation service (BGS) in New Jersey and other bilateral supply contracts, are backed by this generation or may be combined with the use of physical commodity purchases and financial instruments from the market to optimize the economic efficiency of serving our obligations. PSEG Power’s hedging practices help to manage some of the volatility of the merchant power business. More than 70% of PSEG Power’s expected gross margin in 2021 relates to hedging of our energy margin, our expected revenues from the capacity market mechanisms, Zero Emission Certificate (ZEC) revenues and certain ancillary service payments such as reactive power.
As discussed further below under “Wholesale Power Market Design,” FERC issued an order establishing new rules for PJM’s capacity market, extending the PJM Minimum Offer Price Rule (MOPR) to include both new and existing resources that receive or are entitled to receive certain out-of-market payments, with certain exemptions. PSEG Power’s New Jersey nuclear plants that receive ZEC payments will be subject to the new MOPR. In addition, as a result of FERC’s finding that default procurement auctions such as BGS could be considered subsidies, it is possible that other PSEG units could be subject to the MOPR. The MOPR’s floor prices are not expected to prevent either our nuclear or gas-fired units from clearing in the next Reliability Pricing Model (RPM) auction. We cannot predict whether additional changes will be made to the MOPR, or whether changes will occur in the PJM market that would impact our ability to clear any of these units in future RPM auctions.
During 2020, as a result of the ongoing coronavirus pandemic, PSEG Power experienced a decrease in aggregate wholesale electric demand. An extended outbreak could have a material adverse impact on future results of operations and cash flows.
PSEG Power has also implemented protocols to ensure the safety and health of employees at its generation facilities and contractors working at the facilities during planned outages. A prolonged unavailability of employees and contractors due to the ongoing coronavirus pandemic could materially and adversely impact our ability to operate our generation facilities, which would have a material impact on our business, results of operations and cash flows.
PSEG LI
Following the effects of Tropical Storm Isaias, the New York Attorney General initiated an inquiry into PSEG LI’s preparation and response to the storm. In addition, the Department of Public Service (DPS) within the New York State Public Service Commission launched an investigation of state electric service providers, including PSEG LI, and other state telephone, cable and internet providers into their preparation and restoration efforts following Tropical Storm Isaias. Although the inquiry by the New York Attorney General remains pending, the DPS issued an interim storm investigation report. With respect to PSEG LI, the DPS’ report found that PSEG LI violated its Emergency Response Plan and DPS Regulations, and recommended that LIPA
consider taking various actions, including terminating or renegotiating the OSA. LIPA also initiated its own review of PSEG LI’s performance and issued a report with recommendations for improvements to PSEG LI’s structure and processes, including a timeline for implementing those recommendations. That report also recommended that LIPA either renegotiate or terminate the OSA.
PSEG LI agreed with LIPA that it would fund approximately $6.5 million in claims by customers for food and medication spoilage costs incurred as a result of being without electric service during the storm.
In December 2020, LIPA filed a complaint against PSEG LI in New York State court alleging multiple breaches of the OSA in connection with PSEG LI’s preparation for and response to Tropical Storm Isaias seeking specific performance and $70 million in damages. Pursuant to recommendations by the New York State Department of Public Service, LIPA has initiated a series of actions to allow its board to determine whether to seek to terminate the OSA or instead continue with PSEG LI as its Service Provider.
PSEG LI is fully cooperating with the inquiries by the New York Attorney General and the DPS, and we cannot predict their outcome. PSEG LI also continues to work closely with LIPA to address the recommendations in LIPA’s report. PSEG LI intends to vigorously defend itself with regard to the allegations in LIPA’s complaint alleging breaches of the OSA; however a decision in this proceeding requiring specific performance or the payment of damages by PSEG LI or resulting in the termination of the OSA could have a material adverse effect on PSEG’s results of operations and financial condition.
Climate Strategy and Sustainability Efforts
For more than a century, our mission has been to provide safe access to an around-the-clock supply of reliable, affordable power. Building on this mission, we believe in a future where customers universally use less energy, the energy they use is cleaner, and its delivery is more reliable and more resilient. In July 2019, we announced that we expect to cut carbon emissions at PSEG Power’s generation fleet by 80% by 2046, from 2005 levels. We have also announced our vision of attaining net zero- carbon emissions by 2050, assuming advances in technology, public policy and customer behavior.
PSE&G has also undertaken a number of initiatives that support the reduction of greenhouse gas (GHG) emissions and the implementation of energy efficiency initiatives. The first phase of our GSMP replaced approximately 450 miles of cast-iron and unprotected steel gas infrastructure, and the second phase of this program is expected to replace an additional 875 miles of gas pipes through 2023. The GSMP is designed to significantly reduce gas leaks in our distribution system, which would reduce the release of methane, a potent GHG, into the air. In addition, PSE&G’s CEF-EE which was approved by the BPU in September 2020 and the CEF-EC and CEF-EV programs, which were approved by the BPU in January 2021 and the proposed CEF-ES program are intended to support New Jersey’s EMP through programs designed to help customers increase their energy efficiency, support the expansion of the electric vehicle infrastructure in the State, install energy storage capacity to supplement solar generation and enhance grid resiliency, install smart meters and supporting infrastructure to allow for the integration of other clean energy technologies and to more efficiently respond to weather and other outage events.
Offshore Wind
In December 2020, PSEG entered into a definitive agreement with Ørsted North America to acquire a 25% equity interest in Ørsted’s Ocean Wind project. Ocean Wind was selected by New Jersey to be the first offshore wind farm as part of the state’s intention to add 7,500 MW of offshore wind generating capacity by 2035. The Ocean Wind project could provide first power in late 2024. Completion of the acquisition is anticipated to occur in the first half of 2021, subject to approval by the BPU and other customary closing conditions. Additionally, PSEG and Ørsted each owns 50% of Garden State Offshore Energy LLC which holds rights to an offshore wind lease area. PSEG and Ørsted are exploring other offshore wind opportunities.
Operational Excellence
We emphasize operational performance while developing opportunities in both our competitive and regulated businesses. In 2020, our utility continued its efforts to control costs while maintaining strong operational performance and has implemented protocols to ensure that we are providing essential services to our customers during the ongoing coronavirus pandemic in a safe and reliable manner. Flexibility in our generating fleet has allowed us to take advantage of opportunities in a rapidly evolving market as we remain diligent in managing costs.
Financial Strength
Our financial strength is predicated on a solid balance sheet, positive operating cash flow and reasonable risk-adjusted returns on increased investment. Our financial position remained strong during 2020 as we
•maintained sufficient liquidity,
•maintained solid investment grade credit ratings, and
•increased our annual dividend for 2020 to $1.96 per share.
We expect to be able to fund our planned capital requirements, as described in Liquidity and Capital Resources without the issuance of new equity. Our planned capital requirements, which are driven by growth in our regulated utility, and the potential sale of our non-nuclear generation fleet are expected to help support our business and financial profile.
Financial Results
The financial results for PSEG, PSE&G and PSEG Power for the years ended December 31, 2020 and 2019 are presented as follows:
Years Ended December 31,
2020 2019
Millions, except per share data
PSE&G $ 1,327 $ 1,250
PSEG Power 594 468
Other (16) (25)
PSEG Net Income $ 1,905 $ 1,693
PSEG Net Income Per Share (Diluted) $ 3.76 $ 3.33
Our 2020 over 2019 increase in Net Income was due primarily to higher earnings from a gain on the sale of PSEG Power’s ownership interest in a generating facility in 2020 and a loss on its ownership interests in two fossil plants in 2019, T&D investments at PSE&G and pension and OPEB credits. These increases were partially offset at PSEG Power by mark-to-market (MTM) losses in 2020 as compared to gains in the prior year. In addition. higher earnings were reduced by lower energy market prices on lower volumes of electricity sold in PJM and lower capacity revenues which were somewhat tempered by higher ZEC revenues and lower fuel costs at PSEG Power. For a more detailed discussion of our financial results, see Results of Operations.
The greater emphasis on capital spending in recent years for projects at PSE&G relative to PSEG Power, particularly those on which we receive contemporaneous returns at PSE&G has yielded strong results, which when combined with the cash flow generated by PSEG Power, has allowed us to meet customer needs and address market conditions and investor expectations. We continue our focus on operational excellence, financial strength and disciplined investment. These guiding principles have provided the base from which we have been able to execute our strategic initiatives.
Disciplined Investment
We utilize rigorous criteria and consider a number of external factors, focusing on the value for our stakeholders, as well as other impacts, such as the economic impact of the ongoing coronavirus pandemic, when determining how and when to efficiently deploy capital. We principally explore opportunities for investment in areas that complement our existing business and provide reasonable risk-adjusted returns and continuously assess and optimize our business mix as appropriate. In 2020, we
•made additional investments in T&D infrastructure projects on time and on budget,
•continued to execute our Energy Efficiency and other existing BPU-approved utility programs,
•exercised our option to acquire a 25% equity interest in the Ocean Wind offshore wind project in New Jersey while continuing to evaluate potential additional offshore wind opportunities, and
•launched a process to evaluate the potential sale of PSEG Power’s non-nuclear generation business which is expected to improve our business profile and accelerate our transition to a more regulated electric and gas utility, with a contracted energy business.
Regulatory, Legislative and Other Developments
In our pursuit of operational excellence, financial strength and disciplined investment, we closely monitor and engage with stakeholders on significant regulatory and legislative developments. Transmission planning rules and wholesale power market design are of particular importance to our results and we continue to advocate for policies and rules that promote fair and efficient electricity markets. For additional information about regulatory, legislative and other developments that may affect us, see Item 1. Business-Regulatory Issues.
Transmission Rate Proceedings and Return on Equity (ROE)
In May 2020, FERC issued an order revising an earlier order that established a new ROE policy for reviewing existing transmission ROEs. The revised methodology uses the Discounted Cash Flow model, the Capital Asset Pricing model and the risk premium model to determine if an existing base ROE is unjust and unreasonable and, if so, what replacement ROE is
appropriate. FERC’s order indicated that it would not be bound by this revised methodology when considering the just and reasonableness of a utility’s ROE in future proceedings. We continue to analyze the potential impact of these methodologies.
ROE complaints have been pending before FERC regarding MISO transmission owners, the ISO New England Inc. transmission owners and utilities in other jurisdictions. In addition, over the past few years, several companies have negotiated settlements that have resulted in reduced ROEs.
We are engaged in settlement discussions with the BPU Staff and the New Jersey Division of Rate Counsel about the level of PSE&G’s base transmission ROE and other formula rate matters. An adverse change to PSE&G’s base transmission ROE or ROE incentives could be material. We estimate that for each 25 basis point reduction in PSE&G’s base transmission ROE, and all other factors unchanged, PSE&G’s annual Net Income and annual cash inflows would decrease by approximately $15 million. While we cannot predict the outcome of the settlement discussions, it may result in a change to our base transmission ROE that is multiples of this sensitivity measure.
Wholesale Power Market Design
In December 2019, FERC issued an order establishing new rules for PJM’s capacity market, extending the PJM MOPR to include both new and existing resources that receive or are entitled to receive certain out-of-market payments, with certain exemptions.
PSEG Power’s New Jersey nuclear plants that receive ZEC payments will be subject to the new MOPR. Resources that are subject to the MOPR continue to have the ability to justify a bid below the MOPR floor price under the unit-specific exemption. The MOPR floor prices are not expected to prevent either our nuclear units or gas-fired units from clearing in the next RPM auction. In May 2020, FERC issued an order modifying PJM’s methodology for pricing energy reserves. It also directed PJM to use forward-looking energy and ancillary service revenues, which can affect how the MOPR offer floors are calculated. In addition, if one or more electric distribution zones in New Jersey (or another state) were to become fixed resource requirement (FRR) alternative service areas, procurements needed for that area could provide an alternate means for nuclear units whose ability to clear in RPM auctions was affected by the MOPR to provide capacity within PJM. We cannot predict whether additional changes will be made to the MOPR, or whether changes will occur in the PJM market that would impact our ability to clear any of these units in future RPM auctions.
States that have clean energy programs designed to achieve public policy goals that support such resources as solar, offshore wind and nuclear, are not prevented from pursuing those programs by the expanded MOPR and could choose to utilize the existing FRR approach authorized under the PJM tariff. Subsidized units that cannot clear in a RPM capacity auction because of the expanded MOPR could still count as capacity resources to a load serving entity using the FRR approach. In a March 2020 order, the BPU initiated an investigation to examine whether New Jersey can achieve its long-term clean energy and environmental objectives under the current resource adequacy procurement paradigm and potential alternatives. One of the areas of inquiry concerns the potential creation of FRR service areas within New Jersey. We cannot predict the impact these rules or any measures taken by the BPU will have on the capacity market or our generating stations.
In January 2020, New Jersey rejoined the Regional Greenhouse Gas Initiative (RGGI). As a result, generating plants operating in New Jersey, including those owned by PSEG Power, that emit CO2 emissions will be required to procure credits for each ton they emit. In response to RGGI, PJM initiated a process in 2019 to investigate the development of a carbon pricing mechanism that may mitigate the environmental and financial distortions that could occur when emissions “leak” from non-participating states to the RGGI states. If the process leads to a market solution, it could have a material impact on the value of PSEG Power’s generating fleet.
Environmental Regulation
We are subject to liability under environmental laws for the costs of remediating environmental contamination of property now or formerly owned by us and of property contaminated by hazardous substances that we generated. In particular, the historic operations of PSEG companies and the operations of numerous other companies along the Passaic and Hackensack Rivers are alleged by Federal and State agencies to have discharged substantial contamination into the Passaic River/Newark Bay Complex in violation of various statutes. We are also currently involved in a number of proceedings relating to sites where other hazardous substances may have been discharged and may be subject to additional proceedings in the future, and the costs of any such remediation efforts could be material.
For further information regarding the matters described above, as well as other matters that may impact our financial condition and results of operations, see Item 8. Note 15. Commitments and Contingent Liabilities.
Nuclear
In April 2019, PSEG Power’s Salem 1, Salem 2 and Hope Creek nuclear plants were awarded ZECs by the BPU. Pursuant to a process established by the BPU, ZECs are purchased from selected nuclear plants and recovered through a non-bypassable distribution charge in the amount of $0.004 per kilowatt-hour used (which is equivalent to approximately $10 per megawatt
hour generated in payments to selected nuclear plants (ZEC payment)). These nuclear plants are expected to receive ZEC revenue for approximately three years, through May 2022, and will be obligated to maintain operations during that period, subject to exceptions specified in the ZEC legislation. PSEG Power has and will continue to recognize revenue monthly as the nuclear plants generate electricity and satisfy their performance obligations. The ZEC payment may be adjusted by the BPU (a) at any time to offset environmental or fuel diversity payments that a selected nuclear plant may receive from another source or (b) at certain times specified in the ZEC legislation if the BPU determines that the purposes of the ZEC legislation can be achieved through a reduced charge that will nonetheless be sufficient to achieve the State’s air quality and other environmental objectives by preventing the retirement of nuclear plants. For instance, the New Jersey Division of Rate Counsel (New Jersey Rate Counsel), in written comments filed with the BPU, has advocated for the BPU to offset market benefits resulting from New Jersey’s rejoining the RGGI from the ZEC payment. PSEG intends to vigorously defend against these arguments. Due to its preliminary nature, PSEG cannot predict the outcome of this matter.
The BPU’s decision awarding ZECs has been appealed by the New Jersey Rate Counsel. PSEG cannot predict the outcome of this matter.
In October 2020, PSEG Power filed with the BPU its ZEC applications for Salem 1, Salem 2 and Hope Creek for the three-year eligibility period starting in June 2022. No other plants applied for ZECs for this eligibility period. PSEG Power is not aware of any changes from its ZEC application for the first eligibility period that would materially affect its ability to establish eligibility to be awarded ZECs during the second eligibility period. A final BPU decision is expected in April 2021. We cannot predict the outcome of this matter.
In the event that (i) the ZEC program is overturned or is otherwise materially adversely modified through legal process; (ii) the amount of ZEC payments that may be awarded or other terms and conditions of the second ZEC eligibility period proposed by the BPU in its final decision differ from those of the current ZEC period; or (iii) any of the Salem 1, Salem 2 and Hope Creek plants is not awarded ZEC payments by the BPU and does not otherwise experience a material financial change, PSEG Power will take all necessary steps to cease to operate all of these plants. Alternatively, if all of the Salem 1, Salem 2 and Hope Creek plants are selected to continue to receive ZEC payments but the financial condition of the plants is materially adversely impacted by changes in commodity prices, FERC’s changes to the capacity market construct (absent sufficient capacity revenues provided under a program approved by the BPU in accordance with a FERC-authorized capacity mechanism), or, in the case of the Salem nuclear plants, decisions by the EPA and state environmental regulators regarding the implementation of Section 316(b) of the Clean Water Act and related state regulations, or other factors, PSEG Power will take all necessary steps to cease to operate all of these plants. Ceasing operations of these plants would result in a material adverse impact on PSEG’s and PSEG Power’s results of operations.
Nuclear Refueling Outage
The Salem 1 nuclear generating plant completed its scheduled refueling outage in mid-December 2020. During this outage, the plant’s main generator stator replacement was completed successfully. Additionally, all reactor vessel inspections and upgrades were also completed as planned.
Tax Legislation
The Consolidated Appropriations Act, 2021(CAA) was enacted in late December 2020. Our initial analysis of the CAA indicates that this legislation will not have a material impact on the financial condition and cash flows of PSEG, PSE&G and PSEG Power. On December 31, 2020, Notice 2021-05 was issued. For qualifying offshore wind or Federal Land projects, the notice extends the four year continuity safe harbor to no more than ten calendar years after the calendar year during which construction of the project began. We are still in the process of analyzing the CAA.
In July 2020, the Internal Revenue Service (IRS) issued final and proposed regulations addressing the limitation on deductible business interest expense contained in the Tax Cuts and Jobs Act (Tax Act). These regulations retroactively allow depreciation to be added back in computing the 30% adjusted taxable income (ATI) cap, increasing the amount of interest that can be deducted by unregulated businesses in years before 2022. For 2022 and after, the regulations continue to disallow the addback of depreciation in the computation of ATI, effectively lowering the cap on the amount of deductible business interest. The portion of PSEG’s and PSEG Power’s business interest expense that was disallowed in 2018 and 2019 will now be deductible in those respective years.
In March 2020, the federal Coronavirus Aid, Relief, and Economic Security Act (CARES Act) was enacted. The CARES Act allows a five-year carryback of any net operating loss (NOL) generated in a taxable year beginning after December 31, 2017 and before January 1, 2021. We expect that a prolonged coronavirus pandemic, the tax provisions of the CARES Act and any future coronavirus-related federal or state legislation could have a material impact on our effective tax rate and cash tax position.
In November 2018, the IRS issued proposed regulations addressing the interest disallowance rules contained in the Tax Act. For non-regulated businesses, the Tax Act enacted rules that set a cap on the amount of business interest that can be deducted in a
given year. Any amount that is disallowed can be carried forward indefinitely. Amounts recorded under the Tax Act and the CARES Act, such as depreciation and business interest disallowance, are subject to change based on several factors, including among other things, the IRS and state taxing authorities issuing additional guidance and/or further clarification. Any further guidance or clarification could impact PSEG’s, PSE&G’s and PSEG Power’s financial statements.
In July 2018, New Jersey made changes to its income tax laws, including requiring corporate taxpayers to file in a combined reporting group as defined under New Jersey law starting in 2019. This provision includes an exemption for public utilities. We believe PSE&G meets the definition of a public utility and, therefore, will not be included in the combined reporting group. Any further guidance or clarification could impact PSEG’s and PSEG Power’s financial statements.
Future Outlook
Our future success will depend on our ability to continue to maintain strong operational and financial performance to capitalize on or otherwise address regulatory and legislative developments that impact our business and to respond to the issues and challenges described below. In order to do this, we must continue to:
•obtain approval of and execute on our utility capital investment program, which includes the remainder of our recently approved CEF programs and other investments that yield contemporaneous and reasonable risk-adjusted returns, while enhancing the resiliency of our infrastructure, maintaining the reliability of the service we provide to our customers, and aligning our sustainability and climate goals with New Jersey’s energy policy,
•focus on controlling costs while maintaining safety, reliability and customer satisfaction and complying with applicable standards and requirements,
•deliver on our Human Capital Management strategy to attract, develop and retain a diverse, high-performing workforce,
•successfully manage our energy obligations and re-contract our open supply positions in response to changes in prices and demand, mindful of the cost and affordability impacts to our electric and gas distribution customers,
•advocate for the continuation of the ZEC program to preserve New Jersey’s largest zero-carbon generation resource and measures to ensure the implementation by PJM, FERC and state regulators of market design and transmission planning rules that continue to promote fair and efficient electricity markets, including recognition of the cost of emissions,
•engage constructively with our multiple stakeholders, including regulators, government officials, customers, employees, investors, suppliers and the communities in which we do business,
•finalize our strategic alternatives review for PSEG Power’s non-nuclear generating assets and successfully execute any transactions involving those assets as we transform our business mix into a mostly regulated utility and contracted generating company with a carbon-free nuclear and offshore wind fleet,
•successfully operate the LIPA T&D system and manage LIPA’s fuel supply and generation dispatch obligations, and
•manage the risks and opportunities in environmental, social and governance (ESG) matters, which is an integral part of our long-term strategy to be a clean energy leader for the benefit of all stakeholders.
In addition to the risks described elsewhere in this Form 10-K for 2021 and beyond, the key issues and challenges we expect our business to confront include:
•regulatory and political uncertainty, both with regard to future energy policy, design of energy and capacity markets, transmission policy and environmental regulation, as well as with respect to the outcome of any legal, regulatory or other proceedings,
•the continuing impact of the ongoing coronavirus pandemic and the associated economic impact, which could extend beyond the duration of the pandemic,
•the continuing impacts of the Tax and CARES Acts and future changes in federal and state tax laws, and
•the impact of changes in demand, natural gas and electricity prices, increasing environmental compliance costs, and expanded efforts to decarbonize several sectors of the economy.
We continually assess a broad range of strategic options to maximize long-term stockholder value and address the interests of our multiple stakeholders. In assessing our options, we consider a wide variety of factors, including the performance and prospects of our businesses; the views of employees, investors, regulators, customers and rating agencies; our existing indebtedness and restrictions it imposes; and tax considerations, among other things. Strategic options available to us include:
•investments in T&D facilities to enhance reliability, resiliency and modernize the system to meet the growing needs and increasingly higher expectations of customers, and clean energy investments such as CEF-EE, CEF-EV and CEF-ES,
•the disposition or restructuring of our merchant generation business or portions thereof or other existing businesses or the acquisition or development of new businesses,
•investments in offshore wind with long-term contracts that provide predictability and a reasonable risk-adjusted return,
•continued operations of our nuclear generation facilities, to the extent there is sufficient certainty that their operation will render an acceptable risk-adjusted return, and
•acquisitions, dispositions and other transactions involving assets or businesses that could provide value to customers and shareholders.
There can be no assurance, however, that we will successfully develop and execute any of the strategic options noted above, or any additional options we may consider in the future. The execution of any such strategic plan may not have the expected benefits or may have unexpected adverse consequences.
RESULTS OF OPERATIONS
Years Ended December 31,
2020 2019 2018
Earnings (Losses) Millions
PSE&G $ 1,327 $ 1,250 $ 1,067
PSEG Power (A) 594 468 365
Other (B) (16) (25) 6
PSEG Net Income $ 1,905 $ 1,693 $ 1,438
PSEG Net Income Per Share (Diluted) $ 3.76 $ 3.33 $ 2.83
(A)PSEG Power’s results in 2020 include an after-tax gain of $86 million related to the sale of PSEG Power’s ownership interest in the Yards Creek generation facility. PSEG Power’s results in 2019 include an after-tax loss of $286 million related to the sale of PSEG Power’s ownership interests in the Keystone and Conemaugh fossil generation plants. PSEG Power’s results in 2018 include an after-tax gain of $39 million from the sale of its Hudson and Mercer coal/gas generation plants. See Item 8. Note 4. Early Plant Retirements/Asset Dispositions for additional information.
(B)Other includes after-tax activities at the parent company, PSEG LI and Energy Holdings as well as intercompany eliminations.
PSEG Power’s results above include the Nuclear Decommissioning Trust (NDT) Fund activity and the impacts of non-trading commodity MTM activity, which consist of the financial impact from positions with future delivery dates.
The variances in our Net Income attributable to changes related to the NDT Fund and MTM are shown in the following table:
Years Ended December 31, 2020 2019 2018
Millions, after tax
NDT Fund and Related Activity (A) (B) $ 137 $ 152 $ (90)
Non-Trading MTM Gains (Losses) (C) $ (58) $ 205 $ (84)
(A)NDT Fund Income (Expense) includes gains and losses on NDT securities which are recorded in Net Gains (Losses) on Trust Investments. See Item 8. Note 11. Trust Investments for additional information. NDT Fund Income (Expense) also includes interest and dividend income and other costs related to the NDT Fund recorded in Other Income (Deductions), interest accretion expense on PSEG Power’s nuclear Asset Retirement Obligation (ARO) recorded in Operation & Maintenance (O&M) Expense and the depreciation related to the ARO asset recorded in Depreciation and Amortization (D&A) Expense.
(B)Net of tax (expense) benefit of $(94) million, $(103) million and $54 million for the years ended December 31, 2020, 2019 and 2018, respectively.
(C)Net of tax (expense) benefit of $23 million, $(80) million and $33 million for the years ended December 31, 2020, 2019 and 2018, respectively.
Our 2020 year-over-year increase of $212 million in Net Income was driven primarily by
•a gain on sale of PSEG Power’s ownership interest in the Yards Creek generating facility in 2020 (see Item 8. Note 4. Early Plant Retirements/Asset Dispositions),
•an asset impairment in 2019 related to the sale of PSEG Power’s interests in the Keystone and Conemaugh fossil generation plants (see Item 8. Note 4. Early Plant Retirements/Asset Dispositions),
•higher earnings due to investments in T&D programs at PSE&G, and
•higher pension and OPEB credits,
•partially offset by MTM losses in 2020 as compared to significant gains in 2019 at PSEG Power, and
•a decrease at PSEG Power due to lower average realized prices on lower volumes of electricity sold in PJM and under the BGS contracts, as well as lower capacity revenues, partially offset by a net decrease in fuel costs and recognition of a full year of ZEC revenues in 2020 which commenced in April 2019.
Our results of operations are primarily comprised of the results of operations of our principal operating subsidiaries, PSE&G and PSEG Power, excluding charges related to intercompany transactions, which are eliminated in consolidation. For additional information on intercompany transactions, see Item 8. Note 26. Related-Party Transactions.
Increase /
(Decrease) Increase /
(Decrease)
Years Ended December 31,
2020 2019 2018 2020 vs. 2019 2019 vs. 2018
Millions Millions % Millions %
Operating Revenues $ 9,603 $ 10,076 $ 9,696 $ (473) (5) $ 380 4
Energy Costs 3,056 3,372 3,225 (316) (9) 147 5
Operation and Maintenance 3,115 3,111 3,069 4 - 42 1
Depreciation and Amortization 1,285 1,248 1,158 37 3 90 8
(Gain) Loss on Asset Dispositions (123) 402 (54) (525) (131) 456 N/A
Income from Equity Method Investments 14 14 15 - - (1) (7)
Net Gains (Losses) on Trust Investments 253 260 (143) (7) (3) 403 N/A
Other Income (Deductions) 115 125 85 (10) (8) 40 47
Non-Operating Pension and OPEB Credits (Costs) 249 177 76 72 41 101 N/A
Interest Expense 600 569 476 31 5 93 20
Income Tax (Benefit) Expense 396 257 417 139 54 (160) (38)
The 2020, 2019 and 2018 amounts in the preceding table for Operating Revenues and O&M costs each include $520 million, $490 million and $458 million, respectively, for PSEG LI’s subsidiary, Long Island Electric Utility Servco, LLC (Servco). These amounts represent the O&M pass-through costs for the Long Island operations, the full reimbursement of which is reflected in Operating Revenues. See Item 8. Note 5. Variable Interest Entity for further explanation. The following discussions for PSE&G and PSEG Power provide a detailed explanation of their respective variances.
PSE&G
Years Ended December 31, Increase /
(Decrease) Increase /
(Decrease)
2020 2019 2018 2020 vs. 2019 2019 vs. 2018
Millions Millions % Millions %
Operating Revenues $ 6,608 $ 6,625 $ 6,471 $ (17) - $ 154 2
Energy Costs 2,469 2,738 2,520 (269) (10) 218 9
Operation and Maintenance 1,614 1,581 1,575 33 2 6 -
Depreciation and Amortization 887 837 770 50 6 67 9
Gain on Asset Dispositions (1) - - (1) N/A - -
Net Gains (Losses) on Trust Investments 3 2 (1) 1 50 3 N/A
Other Income (Deductions) 108 83 80 25 30 3 4
Non-Operating Pension and OPEB Credits (Costs) 205 150 59 55 37 91 N/A
Interest Expense 388 361 333 27 7 28 8
Income Tax Expense 240 93 344 147 N/A (251) N/A
Year Ended December 31, 2020 as compared to 2019
Operating Revenues decreased $17 million due to changes in delivery, clause, commodity and other operating revenues.
Delivery Revenues increased $219 million.
•Transmission revenues increased $119 million due to higher revenue requirements calculated through our transmission formula rate, primarily to recover required investments.
•Gas distribution revenues increased $4 million due to an increase of $30 million from collection of the GSMP in base rates and an increase in WNC revenues of $19 million. These increases were partially offset by a $44 million decrease from lower sales volumes and $1 million in lower collections of Green Program Recovery Charges (GPRC).
•Electric distribution revenues increased $3 million due primarily to a $12 million increase in sales volumes, partially offset by $9 million in lower collections of GPRC.
•Transmission, electric distribution and gas distribution revenue requirements were $93 million higher as a result of a decrease in the flowback of excess deferred income tax liabilities and tax repair-related accumulated deferred income taxes. This decrease is offset in Income Tax Expense.
Clause Revenues increased $30 million due to $24 million in Tax Adjustment Credits (TAC) and GPRC deferrals and higher SBC charges of $13 million. These increases were partially offset by a $6 million reduction in Margin Adjustment Clause (MAC) revenues and $1 million in lower Solar Pilot Recovery Charge (SPRC) collections. The changes in TAC and GPRC Deferrals, SBC, MAC and SPRC collections were entirely offset by the amortization of related costs (Regulatory Assets) in O&M, D&A and Interest and Tax Expenses. PSE&G does not earn margin on TAC or GPRC deferrals or on SBC, MAC or SPRC collections.
Commodity Revenues decreased $344 million due to lower Gas revenues and lower Electric revenues. The changes in Commodity Revenues for both gas and electric are entirely offset by changes in Energy Costs. PSE&G earns no margin on the provision of basic gas supply service (BGSS) and BGS to retail customers.
•Gas revenues decreased $195 million due primarily to lower BGSS sales volumes of $98 million and lower BGSS prices of $94 million.
•Electric revenues decreased $149 million due to $161 million from lower prices, partially offset by $12 million of higher BGS sales volumes.
Other Operating Revenues increased $78 million due to increases of $42 million in ZEC revenues and $33 million in SREC revenues. The changes in ZEC revenues and SREC revenues are entirely offset by changes to Energy Costs.
Operating Expenses
Energy Costs decreased $269 million. This is entirely offset by changes in Commodity Revenues and Other Operating Revenues.
Operation and Maintenance increased $33 million due primarily to increases of $14 million in gas distribution maintenance costs, $13 million in vegetation management, $9 million in transmission maintenance expenditures, $7 million in storm-related costs and $4 million in distribution corrective and preventative maintenance expenditures. These increases were partially offset by a $4 million decrease in injuries and damages and a $10 million reduction in other operating expenses.
Depreciation and Amortization increased $50 million due primarily to an increase in depreciation of $45 million due to additional plant placed into service and a $4 million increase from the amortization of regulatory assets and software.
Other Income (Deductions) increased $25 million due primarily to an increase in the Allowance for Funds Used During Construction (AFUDC) of $28 million, partially offset by a $3 million net decrease in solar loan interest and other.
Non-Operating Pension and OPEB Credits (Costs) increased $55 million due primarily to a $30 million increase in the expected return on plan assets, a $24 million decrease in interest cost and a $6 million decrease in amortization of the net actuarial loss, partially offset by a $5 million increase in the amortization of net prior service credit.
Interest Expense increased $27 million due primarily to increases of $23 million and $12 million due to net long-term debt issuances in 2020 and 2019, respectively. These increases were partially offset by reductions of $7 million in interest expense related to short-term borrowings and in AFUDC.
Income Tax Expense increased $147 million due primarily to the reduction in the 2020 flowback of excess deferred income tax liabilities, higher pre-tax income in 2020, and an increase in the bad debt flow-through, partially offset by the tax benefit from changes in uncertain tax positions as a result of the settlement of the 2011-2016 federal income tax audits.
Year Ended December 31, 2019 as compared to 2018
See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations in our 2019 Annual Report.
PSEG Power
Years Ended December 31, Increase /
(Decrease) Increase /
(Decrease)
2020 2019 2018 2020 vs. 2019 2019 vs. 2018
Millions Millions % Millions %
Operating Revenues $ 3,634 $ 4,385 $ 4,146 $ (751) (17) $ 239 6
Energy Costs 1,821 2,118 2,197 (297) (14) (79) (4)
Operation and Maintenance 964 1,040 1,053 (76) (7) (13) (1)
Depreciation and Amortization 368 377 354 (9) (2) 23 6
(Gain) Loss on Asset Dispositions (122) 402 (54) (524) N/A 456 N/A
Income from Equity Method Investments 14 14 15 - - (1) (7)
Net Gains (Losses) on Trust Investments 241 253 (140) (12) (5) 393 N/A
Other Income (Deductions) 12 54 21 (42) N/A 33 N/A
Non-Operating Pension and OPEB Credits (Costs) 33 21 15 12 57 6 40
Interest Expense 121 119 76 2 2 43 57
Income Tax Expense (Benefit) 188 203 66 (15) (7) 137 N/A
Year Ended December 31, 2020 as compared to 2019
Operating Revenues decreased $751 million due to changes in generation, gas supply and other operating revenues.
Generation Revenues decreased $613 million due primarily to
•a net decrease of $369 million due to MTM losses in 2020 as compared to MTM gains in 2019. Of this amount, there was a $196 million decrease due to losses on positions reclassified to realized upon settlement in 2020 compared to gains in 2019 coupled with a $173 million decrease due to changes in forward prices this year as compared to last year,
•a net decrease of $171 million due primarily to lower average realized prices in the PJM, New England (NE) and New York (NY) regions coupled with lower volumes sold in the PJM region primarily due to the sale of our ownership
interests in the Keystone and Conemaugh generation plants in 2019. This was partially offset by higher volumes of electricity sold in the NE region, primarily due to the commencement of commercial operations of Bridgeport Harbor Unit 5 (BH5) in June 2019 and higher volumes of electricity sold in the NY region,
•a decrease of $79 million in electricity sold under our BGS contracts primarily due to lower volumes coupled with lower prices, and
•a net decrease of $56 million in capacity revenues due primarily to decreases in auction prices in the PJM region coupled with lower volumes due to the sale of our ownership interests in Keystone and Conemaugh generation plants,
•partially offset by an increase of $70 million due to ZEC revenues that started in April 2019 coupled with increased generation at the nuclear plants in 2020.
Gas Supply Revenues decreased $138 million due primarily to
•a decrease of $153 million in sales under the BGSS contract, of which $99 million was due to a decrease in sales volumes and $54 million to lower average sales prices,
•partially offset by a net increase of $18 million related to sales to third parties, of which $80 million was due to higher volumes sold, partially offset by $62 million due to lower average sales prices.
Operating Expenses
Energy Costs represent the cost of generation, which includes fuel costs for generation as well as purchased energy in the market, and gas purchases to meet PSEG Power’s obligation under its BGSS contract with PSE&G. Energy Costs decreased $297 million due to
Generation costs decreased $156 million due primarily to
•a net decrease of $176 million in fuel costs reflecting lower gas prices in the PJM and NY regions coupled with the utilization of lower volumes of coal in the PJM region primarily due to the sale of our ownership interests in the Keystone and Conemaugh generation plants, and lower volumes of gas in the PJM region. This was partially offset by utilization of higher volumes of gas in the NE region due to the commencement of commercial operations at BH5 in June 2019 coupled with utilization of higher volumes of gas in the NY region, and
•a net decrease of $5 million due to less MTM losses in 2020 as compared to 2019,
•partially offset by a net increase of $24 million in higher emission costs primarily due to New Jersey reentering the RGGI program beginning in 2020.
Gas costs decreased $141 million due primarily to
•a decrease of $160 million related to sales under the BGSS contract, of which $80 million was due to a decrease in the average cost of gas and $80 million to a decrease in send out volumes. Included in the average cost of gas were $18 million of interstate gas pipeline refunds due to a settlement on pipeline rates from prior periods,
•partially offset by a net increase of $18 million related to sales to third parties, of which $73 million was due to higher volumes sold, partially offset by $55 million due to a decrease in the average cost of gas.
Operation and Maintenance decreased $76 million due primarily to a net decrease at our fossil plants due to the sale of our ownership interests in the Keystone and Conemaugh generation plants in September 2019 and our ownership interest in the Yards Creek generation facility in September 2020, as well as a goodwill impairment charge of $16 million in 2019 for the write down of PSEG Power’s carrying value to fair value, partially offset by higher planned outage costs in 2020.
Depreciation and Amortization decreased $9 million due primarily to an extension of the Peach Bottom License which was approved by the NRC in March 2020, partially offset by an increased asset base at Nuclear.
(Gain) Loss on Asset Dispositions reflects a gain on the sale of our ownership interest in the Yards Creek generation facility in September 2020 and a loss on the sale of our ownership interests in the Keystone and Conemaugh generation plants in 2019. See Item 8. Note 4. Early Plant Retirements/Asset Dispositions.
Net Gains (Losses) on Trust Investments decreased $12 million due primarily to a $76 million decrease in net unrealized gains on equity investments in the NDT Fund, partially offset by a $66 million increase in net realized gains on NDT Fund investments.
Other Income (Deductions) decreased $42 million primarily due to purchases of NOLs in 2020 under New Jersey’s Technology Tax Benefit Transfer Program and lower interest and dividend income on NDT Fund investments.
Non-Operating Pension and OPEB Credits (Costs) increased $12 million due to a $9 million decrease in interest cost, a $5 million increase in the expected return on plan assets, and a $3 million decrease in the amortization of the net actuarial loss, partially offset by a $3 million increase in co-owner charges and a $2 million decrease in the amortization of net prior service credit.
Interest Expense increased $2 million due primarily to $17 million of lower capitalized interest in 2020 as a result of BH5 being placed into service in 2019, partially offset by a decrease of $15 million due to debt maturities in April 2020.
Income Tax Expense decreased $15 million due primarily to the benefit of purchasing 2019 NOLs under the New Jersey Technology Tax Benefit Transfer Program in 2020, and the tax benefit from changes in uncertain tax positions as a result of the settlement of the 2011-2016 federal income tax audits, partially offset by higher pre-tax income.
Year Ended December 31, 2019 as compared to 2018
See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations in our 2019 Annual Report.
LIQUIDITY AND CAPITAL RESOURCES
The following discussion of our liquidity and capital resources is on a consolidated basis, noting the uses and contributions, where material, of our two direct major operating subsidiaries.
Financing Methodology
We expect our capital requirements to be met through internally generated cash flows and external financings, consisting of short-term debt for working capital needs and long-term debt for capital investments.
PSE&G’s sources of external liquidity include a $600 million multi-year revolving credit facility. PSE&G uses internally generated cash flow and its commercial paper program to meet seasonal, intra-month and temporary working capital needs. PSE&G does not engage in any intercompany borrowing or lending arrangements. PSE&G maintains back-up facilities in an amount sufficient to cover the commercial paper and letters of credit outstanding. PSE&G’s dividend payments to/capital contributions from PSEG are consistent with its capital structure objectives which have been established to maintain investment grade credit ratings. PSE&G’s long-term financing plan is designed to replace maturities, fund a portion of its capital program and manage short-term debt balances. Generally, PSE&G uses either secured medium-term notes or first mortgage bonds to raise long-term capital.
PSEG, PSEG Power, Energy Holdings, PSEG LI and Services participate in a corporate money pool, an aggregation of daily cash balances designed to efficiently manage their respective short-term liquidity needs. Servco does not participate in the corporate money pool. Servco’s short-term liquidity needs are met through an account funded and owned by LIPA.
PSEG’s available sources of external liquidity may include the issuance of long-term debt securities and the incurrence of additional indebtedness under credit facilities. Our current sources of external liquidity include multi-year revolving credit facilities totaling $1.5 billion. These facilities are available to back-stop PSEG’s commercial paper program, issue letters of credit and for general corporate purposes. PSEG’s credit facilities and the commercial paper program are available to support PSEG working capital needs or to temporarily fund growth opportunities in advance of obtaining permanent financing. PSEG’s credit facilities are also available to make equity contributions or provide liquidity support to its subsidiaries.
PSEG Power’s sources of external liquidity include $2.1 billion of multi-year revolving credit facilities. Additionally, from time to time, PSEG Power maintains bilateral credit agreements designed to enhance its liquidity position. Credit capacity is primarily used to provide collateral in support of PSEG Power’s forward energy sale and forward fuel purchase contracts as the market prices for energy and fuel fluctuate, and to meet potential collateral postings in the event that PSEG Power is downgraded to below investment grade by Standard & Poor’s (S&P) or Moody’s. PSEG Power’s dividend payments to PSEG are also designed to be consistent with its capital structure objectives which have been established to maintain investment grade credit ratings and provide sufficient financial flexibility. Generally, PSEG Power issues senior unsecured debt to raise long-term capital.
Operating Cash Flows
We continue to expect our operating cash flows combined with cash on hand and financing activities to be sufficient to fund planned capital expenditures and provide opportunities for shareholder dividends.
For the year ended December 31, 2020, our operating cash flow decreased by $277 million. The net decrease was primarily due to the net changes from our subsidiaries, as discussed below, and higher tax payments in 2020 at Energy Holdings, offset by net tax refunds in 2020 as compared to net tax payments in 2019 at the parent company.
Given the current economic challenges, PSE&G has informed both our residential customers and state regulators that all non-safety related service disconnections for non-payment will be temporarily suspended. In addition, the current economic
conditions have adversely impacted residential and C&I customer payment patterns. During the moratorium, PSE&G has experienced a significant decrease in cash inflow and higher Accounts Receivable aging and an associated increase in bad debt expense, which we expect will extend beyond the duration of the coronavirus pandemic. While the impact on our results of operations, financial condition and cash flows for the year ended December 31, 2020 was not material, a prolonged coronavirus pandemic and the associated economic impacts, which could extend beyond the duration of the pandemic, could materially impact cash from operations, Accounts Receivable and bad debt expense.
PSE&G
PSE&G’s operating cash flow decreased $82 million from $2,035 million to $1,953 million for the year ended December 31, 2020, as compared to 2019, due primarily to tax payments in 2020 as compared to tax refunds in 2019, increased regulatory deferrals and higher Accounts Receivable reflecting lower collections due to the economic impacts of the pandemic and the moratorium on collections, partially offset by higher earnings and decreases in electric energy and vendor payables.
PSEG Power
PSEG Power’s operating cash flow decreased $368 million from $1,479 million to $1,111 million for the year ended December 31, 2020, as compared to 2019, due to a $359 million reduction resulting from a modest increase in counterparty cash collateral posting requirements in 2020 as compared to a significant reduction in postings in 2019, and tax payments in 2020 as compared to tax refunds in 2019, partially offset by higher earnings and a $51 million increase from net collections of counterparty receivables.
Short-Term Liquidity
PSEG meets its short-term liquidity requirements, as well as those of PSEG Power, primarily through the issuance of commercial paper and, from time to time, short-term loans. PSE&G maintains its own separate commercial paper program to meet its short-term liquidity requirements. Each commercial paper program is fully back-stopped by its own separate credit facilities.
We continually monitor our liquidity and seek to add capacity as needed to meet our liquidity requirements. Each of our credit facilities is restricted as to availability and use to the specific companies as listed below; however, if necessary, the PSEG facilities can also be used to support our subsidiaries’ liquidity needs.
In March 2020, PSEG entered into a $300 million, 364-day term loan agreement, which was prepaid in January 2021. This term loan is not included in the credit facility amounts presented in the following table. In April 2020, PSEG entered into two 364-day term loan agreements for $200 million and $300 million which were prepaid in August 2020.
Our total credit facilities and available liquidity as of December 31, 2020 were as follows:
Company/Facility As of December 31, 2020
Total
Facility Usage Available
Liquidity
Millions
PSEG $ 1,500 $ 665 $ 835
PSE&G 600 117 483
PSEG Power 2,100 168 1,932
Total $ 4,200 $ 950 $ 3,250
As of December 31, 2020, our credit facility capacity was in excess of our projected maximum liquidity requirements over our 12 month planning horizon, including access to capital to meet redemptions. Our maximum liquidity requirements are based on stress scenarios that incorporate changes in commodity prices and the potential impact of PSEG Power losing its investment grade credit rating from S&P or Moody’s, which would represent a three level downgrade from its current S&P or Moody’s ratings. In the event of a deterioration of PSEG Power’s credit rating, certain of PSEG Power’s agreements allow the counterparty to demand further performance assurance. The potential additional collateral that we would be required to post under these agreements if PSEG Power were to lose its investment grade credit rating was approximately $840 million and $974 million as of December 31, 2020 and 2019, respectively.
For additional information, see Item 8. Note 16. Debt and Credit Facilities.
Long-Term Debt Financing
During the next twelve months,
•PSEG has $300 million of 2.00% Senior Notes maturing in November 2021,
•PSE&G has $300 million of 1.90% Medium-Term Notes, Series K, maturing in March 2021 and $134 million of 9.25% Mortgage Bonds Series CC maturing in June 2021, and
•PSEG Power has $700 million of 3.00% Senior Notes maturing in June 2021 and $250 million of 4.15% Senior Notes maturing in September 2021.
For a discussion of our long-term debt transactions during 2020, see Item 8. Note 16. Debt and Credit Facilities.
Guarantor Financial Information
PSEG Power’s Senior Notes are fully and unconditionally guaranteed on a joint and several basis by its subsidiaries, PSEG Fossil LLC, PSEG Nuclear LLC and PSEG Energy Resources & Trade LLC. Each guarantor subsidiary is a wholly owned consolidated subsidiary of PSEG Power.
Summarized financial information is being presented, on a combined basis, only for PSEG Power (parent company) and the guarantors of PSEG Power’s Senior Notes, excluding investments in, and earnings (losses) from, subsidiaries that are not guarantors. All transactions between PSEG Power (parent company) and the guarantor subsidiaries are eliminated in the combined summarized financial information. The required disclosures for the most recent fiscal year have been moved outside the Notes to Consolidated Financial Statements and are provided in the following tables.
Year Ended
December 31, 2020
Millions
Operating Revenues (A) $ 3,564
Operating Income $ 598
Net Income $ 597
(A)Operating Revenues include sales to affiliates of $1,218 million.
As of
December 31, 2020
Millions
Current Receivables from Subsidiaries and Affiliates $ 2,350
Total Current Assets $ 3,365
Noncurrent Receivables from Affiliates $ 17
Total Noncurrent Assets $ 7,228
Current Payables to Subsidiaries and Affiliates $ 258
Total Current Liabilities $ 1,734
Noncurrent Payables to Affiliates $ 57
Total Noncurrent Liabilities $ 4,027
Debt Covenants
Our credit agreements contain maximum debt to equity ratios and other restrictive covenants and conditions to borrowing. We are currently in compliance with all of our debt covenants. Continued compliance with applicable financial covenants will depend upon our future financial position, level of earnings and cash flows, as to which no assurances can be given.
In addition, under its First and Refunding Mortgage (Mortgage), PSE&G may issue new First and Refunding Mortgage Bonds against previous additions and improvements, provided that its ratio of earnings to fixed charges calculated in accordance with its Mortgage is at least 2 to 1, and/or against retired Mortgage Bonds. As of December 31, 2020, PSE&G’s Mortgage coverage ratio was 3.3 to 1 and the Mortgage would permit up to approximately $7.1 billion aggregate principal amount of new Mortgage Bonds to be issued against additions and improvements to its property.
For a discussion of the potential impact on our debt covenants from our strategic alternatives, see Item 1A. Risk Factors.
Default Provisions
Our bank credit agreements and indentures contain various, customary default provisions that could result in the potential
acceleration of indebtedness under the defaulting company’s agreement.
In particular, PSEG’s bank credit agreements contain provisions under which certain events, including an acceleration of material indebtedness under PSE&G’s and PSEG Power’s respective financing agreements, a failure by PSE&G or PSEG Power to satisfy certain final judgments and certain bankruptcy events by PSE&G or PSEG Power, would constitute an event of default under the PSEG bank credit agreements. Under the PSEG bank credit agreements, it would also be an event of default if either PSE&G or PSEG Power ceases to be wholly owned by PSEG. The PSE&G and PSEG Power bank credit agreements include similar default provisions; however, such provisions only relate to the respective borrower under such agreement and its subsidiaries and do not contain cross default provisions to each other. The PSE&G and PSEG Power bank credit agreements do not include cross default provisions relating to PSEG. PSEG Power’s bank credit agreements and outstanding notes also contain limitations on the incurrence of subsidiary debt and liens and certain of PSEG Power’s outstanding notes require PSEG Power to repurchase such notes upon certain change of control events.
There are no cross-acceleration provisions in PSEG’s or PSE&G’s indentures. However, PSEG’s existing notes include a cross acceleration provision that may be triggered upon the acceleration of more than $75 million of indebtedness incurred by PSEG. Such provision does not extend to an acceleration of indebtedness by any of PSEG’s subsidiaries. PSEG Power’s indenture includes a cross acceleration provision similar to that described above for PSEG’s existing notes except that such provision may be triggered upon the acceleration of more than $50 million of indebtedness incurred by PSEG Power or any of its subsidiaries. Such provision does not cross accelerate to PSEG, any of PSEG’s subsidiaries (other than PSEG Power and its subsidiaries), PSE&G or any of PSE&G’s subsidiaries.
Ratings Triggers
Our debt indentures and credit agreements do not contain any material “ratings triggers” that would cause an acceleration of the required interest and principal payments in the event of a ratings downgrade. However, in the event of a downgrade, any one or more of the affected companies may be subject to increased interest costs on certain bank debt and certain collateral requirements. In the event that we are not able to affirm representations and warranties on credit agreements, lenders would not be required to make loans.
In accordance with BPU requirements under the BGS contracts, PSE&G is required to maintain an investment grade credit rating. If PSE&G were to lose its investment grade rating, it would be required to file a plan to assure continued payment for the BGS requirements of its customers.
Fluctuations in commodity prices or a deterioration of PSEG Power’s credit rating to below investment grade could increase PSEG Power’s required margin postings under various agreements entered into in the normal course of business. PSEG Power believes it has sufficient liquidity to meet the required posting of collateral which would likely result from a credit rating downgrade to below investment grade by S&P or Moody’s at today’s market prices.
Pension and NDT Fund Obligations
IRS minimum funding requirements for pension plans are determined based on the fund’s assets and liabilities at the end of a calendar year for the subsequent calendar year. As a result, the market volatility in 2020 associated with the ongoing coronavirus pandemic is not expected to impact PSEG’s pension contributions in 2021. In the event of a prolonged economic downturn associated with the ongoing coronavirus pandemic, our contributions to the pension plans may increase in future periods to meet IRS minimum funding requirements. PSEG had accumulated funding credits totaling approximately $600 million through 2020, which represent historical contributions in excess of IRS minimum funding requirements, and these credits can be applied to offset any future cash contribution obligations.
In addition, the NRC requires a biennial filing of the NDT fund balances against the decommissioning liability estimate. Any funding shortfalls are required to be cured prior to the next NRC reporting period. The market volatility associated in 2020 with the ongoing coronavirus pandemic did not result in any supplemental required funding of the NDT Fund. To the extent of a prolonged economic downturn associated with the ongoing coronavirus pandemic, our funding requirements may increase in future periods to meet NRC minimum funding requirements.
Common Stock Dividends
Years Ended December 31,
Dividend Payments on Common Stock 2020 2019 2018
Per Share $ 1.96 $ 1.88 $ 1.80
in Millions $ 991 $ 950 $ 910
On February 16, 2021, our Board of Directors approved a $0.51 per share common stock dividend for the first quarter of 2021. This reflects an indicative annual dividend rate of $2.04 per share. We expect to continue to pay cash dividends on our common stock; however, the declaration and payment of future dividends to holders of our common stock will be at the discretion of the Board of Directors and will depend upon many factors, including our financial condition, earnings, capital requirements of our businesses, alternate investment opportunities, legal requirements, regulatory constraints, industry practice and other factors that the Board of Directors deems relevant. For additional information related to cash dividends on our common stock, see Item 8. Note 24. Earnings Per Share (EPS) and Dividends.
Credit Ratings
If the rating agencies lower or withdraw our credit ratings, such revisions may adversely affect the market price of our securities and serve to materially increase our cost of capital and limit access to capital. Credit Ratings shown are for securities that we typically issue. Outlooks are shown for Issuer Credit Ratings and can be Stable, Negative, or Positive. There is no assurance that the ratings will continue for any given period of time or that they will not be revised by the rating agencies, if in their respective judgments, circumstances warrant. Each rating given by an agency should be evaluated independently of the other agencies’ ratings. The ratings should not be construed as an indication to buy, hold or sell any security. In August 2020, S&P lowered PSEG Power’s Senior Note rating to BBB from BBB+.
Moody’s (A) S&P (B)
PSEG
Outlook Stable Stable
Senior Notes Baa1 BBB
Commercial Paper P2 A2
PSE&G
Outlook Stable Stable
Mortgage Bonds Aa3 A
Commercial Paper P1 A2
PSEG Power
Outlook Stable Stable
Senior Notes Baa1 BBB
(A)Moody’s ratings range from Aaa (highest) to C (lowest) for long-term securities and P1 (highest) to NP (lowest) for short-term securities.
(B)S&P ratings range from AAA (highest) to D (lowest) for long-term securities and A1 (highest) to D (lowest) for short-term securities.
Other Comprehensive Loss
For the year ended December 31, 2020, we had an Other Comprehensive Loss of $15 million on a consolidated basis. The Other Comprehensive Loss was due primarily to a decrease of $46 million related to pension and other postretirement benefits, partially offset by $25 million of net unrealized gains related to Available-for-Sale Securities, and $6 million of unrealized gains on derivative contracts accounted for as hedges. See Item 8. Note 23. Accumulated Other Comprehensive Income (Loss), Net of Tax for additional information.
CAPITAL REQUIREMENTS
We expect that all of our capital requirements over the next three years will come from a combination of internally generated funds and external debt financing. Projected capital construction and investment expenditures, excluding nuclear fuel purchases, for the next three years are presented in the following table. These projections include AFUDC and Interest Capitalized During Construction for PSE&G and PSEG Power, respectively. These amounts are subject to change, based on various factors. Amounts shown below for PSE&G include currently approved programs. We intend to continue to invest in infrastructure modernization and will seek to extend these and related programs as appropriate. We will also continue to approach potential growth investments for PSEG Power opportunistically, seeking projects that will provide attractive risk-adjusted returns for our shareholders.
2021 2022 2023
Millions
PSE&G:
Transmission $ 955 $ 890 $ 645
Electric Distribution 695 790 1,055
Gas Distribution 875 870 985
Clean Energy 200 375 400
Total PSE&G $ 2,725 $ 2,925 $ 3,085
PSEG Power 100 120 150
Other 25 30 25
Total PSEG $ 2,850 $ 3,075 $ 3,260
PSE&G
PSE&G’s projections for future capital expenditures include material additions and replacements to its T&D systems to meet expected growth and to manage reliability. As project scope and cost estimates develop, PSE&G will modify its current projections to include these required investments. PSE&G’s projected expenditures for the various items reported above are primarily comprised of the following:
•Transmission-investments focused on reliability improvements and replacement of aging infrastructure.
•Electric and Gas Distribution-investments for new business, reliability improvements, flood mitigation, and modernization and replacement of equipment that has reached the end of its useful life.
•Clean Energy-investments associated with grid-connected solar, customer energy efficiency programs, and infrastructure supporting electric vehicles.
In September 2020, the BPU issued an Order approving our CEF-EE program, authorizing PSE&G to commit $1 billion over a three-year period, with the majority of the investment occurring over a five-year period. In January 2021, the BPU issued an Order approving our CEF-EC program, authorizing PSE&G to invest approximately $700 million on the CEF-EC program over a four-year period. Also in January 2021, the BPU issued an Order approving our CEF-EV program, authorizing PSE&G to invest $166 million over what is expected to be a six-year period. See Executive Overview of 2020 and Future Outlook for additional information.
In 2020, PSE&G made $2,507 million of capital expenditures, primarily for T&D system reliability. This does not include expenditures for cost of removal, net of salvage, of $106 million, which are included in operating cash flows.
PSEG Power
PSEG Power’s projected expenditures are primarily comprised of investments to replace major parts and enhance operational performance.
In 2020, PSEG Power made $195 million of capital expenditures, excluding $209 million for nuclear fuel, primarily related to various nuclear and solar projects.
Offshore Wind
The above table does not reflect our expected long-term investments in offshore wind projects. Following the completion of our acquisition of a 25% equity interest in Orsted’s Ocean Wind project, which is subject to the approval of the BPU and other customary closing conditions, we currently expect to make investments in the project in 2021 relating to our initial capital investment and to fund construction and operations planning activities. Over the course of the project, which could provide first power in late 2024, our investments are expected to be substantial.
Disclosures about Contractual Obligations
The following table reflects our contractual cash obligations in the respective periods in which they are due. In addition, the table summarizes anticipated debt maturities for the years shown. For additional information, see Item 8. Note 16. Debt and Credit Facilities.
The table below does not reflect any anticipated cash payments for pension obligations due to uncertain timing of payments or liabilities for uncertain tax positions since we are unable to reasonably estimate the timing of liability payments in individual years beyond 12 months due to uncertainties in the timing of the effective settlement of tax positions. See Item 8. Note 22. Income Taxes for additional information.
Total
Amount
Committed Less
Than
1 Year 2 - 3
Years 4 - 5
Years Over
5 Years
Millions
Contractual Cash Obligations
Long-Term Recourse Debt Maturities
PSEG $ 2,946 $ 300 $ 700 $ 1,300 $ 646
PSE&G 10,999 434 825 1,100 8,640
PSEG Power 2,348 950 994 - 404
Interest on Recourse Debt
PSEG 315 68 105 54 88
PSE&G 6,650 390 756 683 4,821
PSEG Power 487 93 132 70 192
Operating Leases
PSE&G 127 16 24 18 69
PSEG Power 89 14 22 6 47
Services 150 15 30 30 75
Energy-Related Purchase Commitments
PSEG Power 2,252 688 804 477 283
Total Contractual Cash Obligations $ 26,363 $ 2,968 $ 4,392 $ 3,738 $ 15,265
Liability Payments for Uncertain Tax Positions
PSEG $ 12 $ 12 $ - $ - $ -
PSE&G 12 12 - - -
PSEG Power - - - - -
OFF-BALANCE SHEET ARRANGEMENTS
PSEG and PSEG Power issue guarantees, primarily in conjunction with certain of PSEG Power’s energy contracts. See Item 8. Note 15. Commitments and Contingent Liabilities for further discussion.
CRITICAL ACCOUNTING ESTIMATES
Under accounting guidance generally accepted in the United States (GAAP), many accounting standards require the use of estimates, variable inputs and assumptions (collectively referred to as estimates) that are subjective in nature. Because of this, differences between the actual measure realized versus the estimate can have a material impact on results of operations, financial position and cash flows. We have determined that the following estimates are considered critical to the application of rules that relate to the respective businesses.
Accounting for Pensions and Other Postretirement Benefits (OPEB)
PSEG sponsors qualified and nonqualified pension plans and OPEB plans covering PSEG’s and its participating affiliates’ current and former employees who meet certain eligibility criteria. In late June 2019, PSEG approved a plan amendment to its qualified pension plan, effective July 1, 2019. The amendment involved the spin-off of predominantly active participants from the existing qualified pension plan (Pension Plan) into a new qualified pension plan (Pension Plan II). See Item 8. Note 14. Pension, Other Postretirement Benefits (OPEB) and Savings Plans for additional information. The market-related value of plan assets held for the qualified pension and OPEB plans is equal to the fair value of these assets as of year-end. The plan assets are comprised of investments in both debt and equity securities which are valued using quoted market prices, broker or dealer quotations, or alternative pricing sources with reasonable levels of price transparency. Plan assets also include investments in
unlisted real estate which is valued via third-party appraisals. We calculate pension and OPEB costs using various economic and demographic assumptions.
Assumptions and Approach Used: Economic assumptions include the discount rate and the long-term rate of return on trust assets. Demographic pension and OPEB assumptions include projections of future mortality rates, pay increases and retirement patterns, as well as projected health care costs for OPEB.
Assumption 2020 2019 2018
Pension
Discount Rate 2.61 % 3.30 % 4.41 %
Expected Rate of Return on Plan Assets 7.70 % 7.80 % 7.80 %
OPEB
Discount Rate 2.46 % 3.20 % 4.31 %
Expected Rate of Return on Plan Assets 7.70 % 7.79 % 7.80 %
The discount rate used to calculate pension and OPEB obligations is determined as of December 31 each year, our measurement date. The discount rate is determined by developing a spot rate curve based on the yield to maturity of a universe of high quality corporate bonds with similar maturities to the plan obligations. The spot rates are used to discount the estimated plan distributions. The discount rate is the single equivalent rate that produces the same result as the full spot rate curve.
Our expected rate of return on plan assets reflects current asset allocations, historical long-term investment performance and an estimate of future long-term returns by asset class, long-term inflation assumptions and a premium for active management.
We utilize a corridor approach that reduces the volatility of reported costs/credits. The corridor requires differences between actuarial assumptions and plan results be deferred and amortized as part of the costs/credits. This occurs only when the accumulated differences exceed 10% of the greater of the benefit obligation or the fair value of plan assets as of each year-end. For the Pension Plan, the excess would be amortized over the average remaining expected life of inactive participants, which is approximately nineteen years. For Pension Plan II, the excess would be amortized over the average remaining service period of active employees, which is approximately fourteen years.
Effect if Different Assumptions Used: As part of the business planning process, we have modeled future costs assuming a 7.70% expected rate of return and a 2.61% discount rate for 2021 pension costs/credits and a 2.46% discount rate for 2021 OPEB costs/credits. Based upon these assumptions, we have estimated a net periodic pension credit in 2021 of approximately $82 million, or $142 million, net of amounts capitalized, and a net periodic OPEB credit in 2021 of approximately $96 million, or $100 million, net of amounts capitalized. Actual future pension costs/credits and funding levels will depend on future investment performance, changes in discount rates, market conditions, funding levels relative to our projected benefit obligation and accumulated benefit obligation and various other factors related to the populations participating in the pension plans. Actual future OPEB costs/credits will depend on future investment performance, changes in discount rates, market conditions, and various other factors.
The following chart reflects the sensitivities associated with a change in certain assumptions. The effects of the assumption changes shown below solely reflect the impact of that specific assumption.
% Change Impact on
Benefit Obligation as of December 31, 2020 Increase to Costs in 2021 Increase to
Costs, net of Amounts Capitalized
in 2021
Assumption Millions
Pension
Discount Rate (1)% $ 987 $ 37 $ 26
Expected Rate of Return on Plan Assets (1)% N/A $ 62 $ 62
OPEB
Discount Rate (1)% $ 143 $ 17 $ 16
Expected Rate of Return on Plan Assets (1)% N/A $ 5 $ 5
See Item 7A. Quantitative and Qualitative Disclosures About Market Risk for additional information.
Derivative Instruments
The operations of PSEG, PSEG Power and PSE&G are exposed to market risks from changes in commodity prices, interest rates and equity prices that could affect their results of operations and financial condition. Exposure to these risks is managed through normal operating and financing activities and, when appropriate, through executing derivative transactions. Derivative instruments are used to create a relationship in which changes to the value of the assets, liabilities or anticipated transactions exposed to market risks are expected to be offset by changes in the value of these derivative instruments.
Current accounting guidance requires us to recognize all derivatives on the balance sheet at their fair value, except for derivatives that qualify for and are designated as normal purchases and normal sales contracts.
Assumptions and Approach Used: In general, the fair value of our derivative instruments is determined primarily by end of day clearing market prices from an exchange, such as the New York Mercantile Exchange, Intercontinental Exchange and Nodal Exchange, or auction prices. Fair values of other energy contracts may be based on broker quotes.
For a small number of contracts where limited observable inputs or pricing information are available, modeling techniques are employed in determination of their fair value using assumptions reflective of contractual terms, current market rates, forward price curves, discount rates and risk factors, as applicable.
For our wholesale energy business, many of the forward sale, forward purchase, option and other contracts are derivative instruments that hedge commodity price risk, but do not meet the requirements for, or are not designated as, either cash flow or fair value hedge accounting. The changes in value of such derivative contracts are marked to market through earnings as the related commodity prices fluctuate. As a result, our earnings may experience significant fluctuations depending on the volatility of commodity prices.
Effect if Different Assumptions Used: Any significant changes to the fair market values of our derivatives instruments could result in a material change in the value of the assets or liabilities recorded on our Consolidated Balance Sheets and could result in a material change to the unrealized gains or losses recorded in our Consolidated Statements of Operations.
For additional information regarding Derivative Financial Instruments, see Item 8. Note 1. Organization, Basis of Presentation and Summary of Significant Accounting Policies, Note 18. Financial Risk Management Activities and Note 19. Fair Value Measurements.
Long-Lived Assets
Management evaluates long-lived assets for impairment and reassesses the reasonableness of their related estimated useful lives whenever events or changes in circumstances warrant assessment. Such events or changes in circumstances may be as a result of significant adverse changes in regulation, business climate, counterparty credit worthiness, market conditions, or a determination that it is more-likely-than-not that an asset or asset group will be sold or retired before its estimated useful life, an asset group’s carrying amount may not be recoverable or an asset’s probability of operating through its estimated remaining useful life changes.
Assumptions and Approach Used: In the event certain triggers exist indicating an asset/asset group may not be recoverable, an undiscounted cash flow test is performed to determine if an impairment exists. When the carrying value of a long-lived asset/asset group exceeds the undiscounted estimate of future cash flows associated with the asset/asset group, an impairment may exist to the extent that the fair value of the asset/asset group is less than its carrying amount.
For PSEG Power, cash flows for long-lived assets and asset groups are determined at the lowest level for which identifiable cash flows are largely independent of the cash flows of other assets and liabilities. The cash flows from the generation units are generally evaluated at a regional portfolio level (PJM, NYISO, ISO-NE), regardless of generation fuel type, along with cash flows generated from the customer supply and risk management activities, inclusive of cash flows from contracts, including those that are accounted for as derivatives and meet the normal purchases and normal sales scope exception. In certain cases, generation assets are evaluated on an individual basis where those assets are individually contracted on a long-term basis with a third party and operations are independent of other generation assets (typically PSEG Power’s solar units and Kalaeloa). These tests require significant estimates and judgment when developing expected future cash flows. Significant inputs include, but are not limited to, forward power prices, fuel costs, dispatch rates, other operating and capital expenditures, the cost of borrowing and asset sale prices and probabilities associated with any potential sale prior to the end of the estimated useful life or the early retirement of assets. The assumptions used by management incorporate inherent uncertainties that are at times difficult to predict and could result in impairment charges or accelerated depreciation in future periods if actual results materially differ from the estimated assumptions utilized in our forecasts.
As a result of the strategic review of PSEG Power’s non-nuclear generating assets, and the launch in the fourth quarter of 2020 of an associated marketing process for their potential disposition, PSEG Power performed an impairment assessment of its PJM, NYISO and ISO-NE asset groupings, as well as for its solar assets, as of September 30, 2020 and December 31, 2020. The assessments included probability weightings assigned to undiscounted cash flow scenarios of retaining the assets through
the end of their estimated useful lives and a successful disposition of the non-nuclear assets in 2021. Estimates of cash flows associated with a sale scenario were based on management’s expectations of the fair value of such assets. The probability weighted aggregation of undiscounted cash flows for each of the asset groupings expected to result from the use and potential disposition of the asset groups exceeded their carrying value at the above mentioned September 30, 2020 and December 31, 2020 assessment dates. As such, it demonstrated that no impairment exists for any of the asset groupings and they continue to remain classified as held for use as of December 31, 2020. Management expects that a change in the probability of a successful disposition based upon further progression in the marketing process, but prior to meeting all necessary held-for-sale classification criteria, would result in an impairment of the ISO-NE asset grouping, which would be material. Furthermore, a change to a held-for-sale classification from a held-for-use classification would result in an impairment of the PJM, NYISO and ISO-NE asset groupings, which would be material.
In addition, long-lived assets are depreciated under the straight-line method based on estimated useful lives. An asset’s operating useful life is generally based upon operational experience with similar asset types and other non-operational factors. In the ordinary course, management, together with an asset’s co-owners in the case of certain of our jointly-owned assets, makes a number of decisions that impact the operation of our generation assets beyond the current year. These decisions may have a direct impact on the estimated remaining useful lives of our assets and will be influenced by the financial outlook of the assets, including future market conditions such as forward energy and capacity prices, operating and capital investment costs and any state or federal legislation and regulations, among other items.
Effect if Different Assumptions Used: The above cash flow tests, and fair value estimates and estimated remaining useful lives may be impacted by a change in the assumptions noted above and could significantly impact the outcome, triggering additional impairment tests, write-offs or accelerated depreciation. For additional information on the potential impacts on our future financial statements that may be caused by a change in the assumptions noted above, see Item 8. Note 4. Early Plant Retirements/Asset Dispositions.
Asset Retirement Obligations (ARO)
PSE&G, PSEG Power and Services recognize liabilities for the expected cost of retiring long-lived assets for which a legal obligation exists. These AROs are recorded at fair value in the period in which they are incurred and are capitalized as part of the carrying amount of the related long-lived assets. PSE&G, as a rate-regulated entity, recognizes Regulatory Assets or Liabilities as a result of timing differences between the recording of costs and costs recovered through the rate-making process. We accrete the ARO liability to reflect the passage of time with the corresponding expense recorded in O&M Expense.
Assumptions and Approach Used: Because quoted market prices are not available for AROs, we estimate the initial fair value of an ARO by calculating discounted cash flows that are dependent upon various assumptions, including:
•estimation of dates for retirement, which can be dependent on environmental and other legislation,
•amounts and timing of future cash expenditures associated with retirement, settlement or remediation activities,
•discount rates,
•cost escalation rates,
•market risk premium,
•inflation rates, and
•if applicable, past experience with government regulators regarding similar obligations.
We obtain updated cost studies triennially unless new information necessitates more frequent updates. The most recent cost study was done in 2018. When we revise any assumptions used to calculate fair values of existing AROs, we adjust the ARO balance and corresponding long-lived asset which generally impacts the amount of accretion and depreciation expense recognized in future periods.
Nuclear Decommissioning AROs
AROs related to the future decommissioning of PSEG Power’s nuclear facilities comprised 95% or $852 million of PSEG Power’s total AROs as of December 31, 2020. PSEG Power determines its AROs for its nuclear units by assigning probability weighting to various discounted cash flow outcomes for each of its nuclear units that incorporate the assumptions above as well as:
•financial feasibility and impacts on potential early shutdown,
•license renewals,
•SAFSTOR alternative, which assumes the nuclear facility can be safely stored and subsequently decommissioned in a period within 60 years after operations,
•DECON alternative, which assumes decommissioning activities begin after operations, and
•recovery from the federal government of costs incurred for spent nuclear fuel.
Effect if Different Assumptions Used: Changes in the assumptions could result in a material change in the ARO balance sheet obligation and the period over which we accrete to the ultimate liability. Had the following assumptions been applied, our estimates of the approximate impacts on the Nuclear ARO as of December 31, 2020 are as follows:
•A decrease of 1% in the discount rate would result in a $33 million increase in the Nuclear ARO.
•An increase of 1% in the inflation rate would result in a $292 million increase in the Nuclear ARO.
•If we were not reimbursed by the federal government for spent fuel costs as prescribed under the Nuclear Waste Policy Act, the Nuclear ARO would increase by $399 million.
•If we would elect or be required to decommission under a DECON alternative at Salem and Hope Creek, the Nuclear ARO would increase by $710 million.
•If PSEG Power were to increase its early shutdown probability to 100% and retires Salem 1 and Hope Creek starting in 2022 and Salem 2 in 2023, which is significantly earlier than the end of their current license periods, the Nuclear ARO would increase by $217 million. For additional information, see Item 8. Note 4. Early Plant Retirements/Asset Dispositions.
Accounting for Regulated Businesses
PSE&G prepares its financial statements to comply with GAAP for rate-regulated enterprises, which differs in some respects from accounting for non-regulated businesses. In general, accounting for rate-regulated enterprises should reflect the economic effects of regulation. As a result, a regulated utility is required to defer the recognition of costs (Regulatory Asset) or recognize obligations (Regulatory Liability) if the rates established are designed to recover the costs and if the competitive environment makes it probable that such rates can be charged or collected. This accounting results in the recognition of revenues and expenses in different time periods than that of enterprises that are not regulated.
Assumptions and Approach Used: PSE&G recognizes Regulatory Assets where it is probable that such costs will be recoverable in future rates from customers and Regulatory Liabilities where it is probable that refunds will be made to customers in future billings. The highest degree of probability is an order from the BPU either approving recovery of the deferred costs over a future period or requiring the refund of a liability over a future period.
Virtually all of PSE&G’s Regulatory Assets and Regulatory Liabilities are supported by BPU orders. In the absence of an order, PSE&G will consider the following when determining whether to record a Regulatory Asset or Liability:
•past experience regarding similar items with the BPU,
•treatment of a similar item in an order by the BPU for another utility,
•passage of new legislation, and
•recent discussions with the BPU.
All deferred costs are subject to prudence reviews by the BPU. When the recovery of a Regulatory Asset or payment of a Regulatory Liability is no longer probable, PSE&G charges or credits earnings, as appropriate.
Effect if Different Assumptions Used: A change in the above assumptions may result in a material impact on our results of operations or our cash flows. See Item 8. Note 7. Regulatory Assets and Liabilities for a description of the amounts and nature of regulatory balance sheet amounts.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT
MARKET RISK
The risk inherent in our market-risk sensitive instruments and positions is the potential loss arising from adverse changes in commodity prices, equity security prices and interest rates as discussed in the Notes to Consolidated Financial Statements. It is our policy to use derivatives to manage risk consistent with business plans and prudent practices. We have a Risk Management
Committee comprised of executive officers who utilize a risk oversight function to ensure compliance with our corporate policies and risk management practices.
Additionally, we are exposed to counterparty credit losses in the event of non-performance or non-payment. We have a credit management process, which is used to assess, monitor and mitigate counterparty exposure. In the event of non-performance or non-payment by a major counterparty, there may be a material adverse impact on our financial condition, results of operations or net cash flows.
Commodity Contracts
The availability and price of energy-related commodities are subject to fluctuations from factors such as weather, environmental policies, changes in supply and demand, state and federal regulatory policies, market rules and other events. To reduce price risk caused by market fluctuations, we enter into supply contracts and derivative contracts, including forwards, futures, swaps and options with approved counterparties. These contracts, in conjunction with physical sales and other services, help reduce risk and optimize the value of owned electric generation capacity.
Value-at-Risk (VaR) Models
VaR represents the potential losses, under normal market conditions, for instruments or portfolios due to changes in market factors, for a specified time period and confidence level. We estimate VaR across our commodity businesses.
MTM VaR consists of MTM derivatives that are economic hedges. The MTM VaR calculation does not include market risks associated with activities that are subject to accrual accounting, primarily our generating facilities and some load-serving activities.
The VaR models used are variance/covariance models adjusted for the change of positions with 95% and 99.5% confidence levels and a one-day holding period for the MTM activities. The models assume no new positions throughout the holding periods; however, we actively manage our portfolio.
MTM VaR
Millions
Years Ended December 31, 2020 2019
95% Confidence Level, Loss could exceed VaR one day in 20 days
Period End $ 16 $ 9
Average for the Period $ 10 $ 12
High $ 18 $ 35
Low $ 5 $ 5
99.5% Confidence Level, Loss could exceed VaR one day in 200 days
Period End $ 24 $ 14
Average for the Period $ 16 $ 19
High $ 29 $ 54
Low $ 8 $ 8
See Item 8. Note 18. Financial Risk Management Activities for a discussion of credit risk.
Interest Rates
We are subject to the risk of fluctuating interest rates in the normal course of business. We manage interest rate risk by targeting a balanced debt maturity profile which limits refinancing in any given period or interest rate environment. In addition, we use a mix of fixed and floating rate debt, interest rate swaps and interest rate lock agreements.
As of December 31, 2020, a hypothetical 10% increase in market interest rates would result in
•no material impact on annual interest costs related to either the current or the long-term portion of long-term debt, and
•a $357 million decrease in the fair value of debt, including a $16 million decrease at PSEG, a $328 million decrease at PSE&G and a $13 million decrease at PSEG Power.
Debt and Equity Securities
We have $6.9 billion of assets in a trust for our pension and OPEB plans. Although fluctuations in market prices of securities within this portfolio do not directly affect our earnings in the current period, changes in the value of these investments could affect
•our future contributions to these plans,
•our financial position if our accumulated benefit obligation under our pension plans exceeds the fair value of the pension trust funds, and
•future earnings, as we could be required to adjust pension expense and the assumed rate of return.
The NDT Fund is comprised primarily of fixed income and equity securities. As of December 31, 2020, the portfolio included $1.4 billion of equity securities and $1.1 billion in fixed income securities. The fair market value of the assets in the NDT Fund will fluctuate primarily depending upon the performance of equity markets. As of December 31, 2020, a hypothetical 10% change in the equity market would impact the value of the equity securities in the NDT Fund by approximately $135 million.
We use duration to measure the interest rate sensitivity of the fixed income portfolio. Duration is a summary statistic of the effective average maturity of the fixed income portfolio. The benchmark for the fixed income component of the NDT Fund currently has a duration of 6.22 years and a yield of 1.14%. The portfolio’s value will appreciate or depreciate by the duration with a 1% change in interest rates. As of December 31, 2020, a hypothetical 1% increase in interest rates would result in a decline in the market value for the fixed income portfolio of approximately $71 million.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
This combined Form 10-K is separately filed by PSEG, PSE&G and PSEG Power. Information contained herein relating to any individual company is filed by such company on its own behalf. PSE&G and PSEG Power each make representations only as to itself and make no representations as to any other company.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of
Public Service Enterprise Group Incorporated
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Public Service Enterprise Group Incorporated and subsidiaries (the “Company” or PSEG) as of December 31, 2020 and 2019, the related consolidated statements of operations, comprehensive income, stockholders' equity, and cash flows, for each of the three years in the period ended December 31, 2020, the related notes and the consolidated financial statement schedule listed in the Index at Item 15(B)(a) (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the consolidated financial position of the Company as of December 31, 2020 and 2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2020, in conformity with accounting principles generally accepted in the United States of America.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company's internal control over financial reporting as of December 31, 2020, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated February 26, 2021, expressed an unqualified opinion on the Company's internal control over financial reporting.
Basis for Opinion
These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matters
The critical audit matters communicated below are matters arising from the current-period audit of the financial statements that were communicated or required to be communicated to the audit committee and that (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.
Early Plant Retirements - Nuclear - Refer to Notes 4 and 13 to the financial statements
Critical Audit Matter Description
PSEG’s wholly-owned subsidiary PSEG Power LLC (PSEG Power) owns and operates nuclear plants in New Jersey and has recorded associated asset retirement obligations (ARO) for their eventual decommissioning. In April 2019, the New Jersey Board of Public Utilities (BPU) awarded Zero Emission Certificates (ZEC) to PSEG Power’s Salem 1, Salem 2 and Hope Creek nuclear plants for an initial period of approximately three years through May 2022. The initial ZEC award has been appealed by the New Jersey Rate Counsel and PSEG Power cannot predict the outcome of this matter. In October, 2020, PSEG Power filed its application for the second eligibility period beginning in June 2022.
In the event that (i) the ZEC program is overturned or is otherwise materially adversely modified through legal process; (ii) the amount of ZEC payments that may be awarded or other terms and conditions of the second ZEC eligibility period proposed by the BPU in its final decision differ from those of the current ZEC period; or (iii) any of the Salem 1, Salem 2 and Hope Creek plants is not awarded ZEC payments by the BPU and does not otherwise experience a material financial change, PSEG Power has disclosed that it will take all necessary steps to cease to operate these nuclear plants. This would result in material charges
associated with accelerated depreciation and amortization, impairment charges, and accelerated asset retirement costs, among other costs.
We identified the potential early retirement of the nuclear plants as a critical audit matter because of the significant estimates and assumptions management made in determining the useful lives of the nuclear plants and in evaluating the recorded investments in the nuclear plants for potential impairment. Further, management’s estimates used in recording the ARO included a number of assumptions, including the timing of cash flows associated with the eventual decommissioning of the nuclear plants following the retirement of the assets. Auditing each of these assumptions required a high degree of auditor judgment.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the potential early retirement of the nuclear plants and the related impact on the recorded investments in the nuclear plants and the related ARO included the following, among others:
•We tested the effectiveness of controls over the evaluation of potential impairment indicators, including management’s consideration of legal and regulatory matters related to ZECs.
•We tested the effectiveness of controls over the evaluation of retirement date assumptions used in the calculation of the ARO, including the probability weighting of the various cash flow scenarios.
•We evaluated management’s judgments over the probability of early retirement of the nuclear plants and impairment triggers including considerations of regulatory matters for the second ZEC eligibility period.
•We evaluated management’s assumptions over the weighted-probability of early retirement of the nuclear plants used in calculating the recorded nuclear ARO balance.
•We requested and received a written response from internal counsel and external legal firms representing PSEG and evaluated the legal conclusions for consistency with those used in management’s accounting judgments and disclosures.
•We obtained written representations from management regarding their intent to cease to operate the nuclear plants in the event that certain legal, regulatory, and economic matters are not favorably resolved.
•We evaluated the related disclosures for consistency with our understanding.
Asset Dispositions - Potential Sale of Non-Nuclear Assets - Impairment Tests - Refer to Note 4 to the financial statements
Critical Audit Matter Description
In July 2020, PSEG Power announced that it is exploring strategic alternatives for its non-nuclear generating fleet, which includes more than 6,750 MW of fossil generation located in New Jersey, Connecticut, New York and Maryland. As a result, PSEG Power performed impairment tests for its portfolio of assets in the PJM, NYISO and NEPOOL regions. The assessments included probability weightings assigned to undiscounted cash flow scenarios of retaining the assets through their estimated useful lives and a potential disposition of the assets. As of December 31, 2020, the estimated undiscounted future cash flows of each of the asset groups exceeded the carrying amount and no impairment was identified.
We identified the impairment tests over the PJM, NYISO and NEPOOL asset groupings as a critical audit matter because of the significant management judgements and estimates related to asset grouping conclusions, the probability weighting of the outcomes of various scenarios, and the significant inputs utilized in the impairment test to determine the estimated undiscounted cash flows. Those inputs include estimated forward power prices, fuel costs and dispatch rates as well as estimates of fair value to be received upon any disposition of assets. Auditing these estimates and assumptions required a high degree of auditor judgment and the involvement of our fair value specialists.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the impairment tests over the PJM, NYISO and NEPOOL asset groupings included the following, among others:
•We tested the effectiveness of controls over management’s impairment tests including considerations of asset groupings, the significant inputs utilized to determine estimated undiscounted cash flows, and the weighted probabilities assigned to the outcome of various scenarios.
•We evaluated management’s conclusions regarding the asset groupings utilized for the purposes of the impairment tests.
•With the assistance of our fair value specialists, we evaluated the significant inputs utilized within management’s impairment tests including forward power prices, fuel costs, dispatch rates and estimates of the fair value to be received upon any disposition of assets.
•We evaluated management’s assumptions related to the weighted probabilities assigned to the outcome of various scenarios.
•We evaluated the related disclosures for consistency with our understanding.
Regulatory Assets and Liabilities - Income Taxes-Refer to Notes 1, 7 and 22 to the financial statements
Critical Audit Matter Description
PSEG’s subsidiary, Public Service Electric and Gas Company (PSE&G), is an electric and gas transmission and distribution utility regulated by the BPU and the Federal Energy Regulatory Commission. Management believes that PSE&G’s transmission and distribution businesses continue to meet the accounting requirements for rate-regulated entities, and PSE&G’s financial statements reflect the economic effects of cost-based rate regulation.
Through the rate-making process, PSE&G’s rates to customers also include the recovery of income tax expense associated with PSE&G’s electric and gas distribution and electric transmission operations. PSE&G has recorded regulatory liabilities for excess accumulated deferred income taxes (ADIT) which will be refunded to customers in future periods. PSE&G’s most recent electric and gas distribution base rate case, concluded in 2018, established the tax adjustment credit (TAC) that provides for the refund of these excess ADIT regulatory liabilities as well as the flow through to customers of historical and current accumulated deferred income taxes for tax-deductible repairs. The flow through of the tax benefits results in lower revenues and lower income tax expense, as well as the recognition of a regulatory asset, as management believes it is probable that the accumulated tax benefits, treated as a flow-through item to PSE&G customers, will be recovered from customers in the future.
We identified the accounting for the TAC as a critical audit matter due to the complexity in accounting for the impact of rate regulation on income tax expense. Auditing management’s assertion that the TAC regulatory assets are probable of future recovery, and that the accounting for the TAC is accurately recorded and reported, requires auditor judgment and specialized knowledge of accounting matters specific to rate regulation. Further, the determination of the estimated benefit of current tax-deductible repairs under the Internal Revenue Code, and the resulting impacts on the TAC regulatory asset and income tax expense recorded in the financial statements is complex and required a high degree of auditor judgment and the involvement of our income tax specialists.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures to evaluate the accounting for the TAC and the associated regulatory assets, regulatory liabilities, and income tax expense included the following, among others:
•We tested the effectiveness of controls over the calculation of the amounts refunded through the TAC, including controls over the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering the TAC regulatory assets in future rates.
•We evaluated management’s analysis over the assertion that the TAC regulatory assets are probable of recovery.
•We evaluated relevant regulatory orders related to the ratemaking treatment of income taxes.
•With the assistance of our income tax specialists, we tested the accuracy of income tax expense, regulatory assets and regulatory liabilities associated with the TAC.
•We evaluated the financial statement presentation and related disclosures for consistency with our understanding.
Commitments and Contingent Liabilities - Passaic River Environmental Liability-Refer to Note 15 to the financial statements
Critical Audit Matter Description
As described in Note 15, the U.S. Environmental Protection Agency (EPA) has designated a 17-mile stretch of the lower Passaic River (Lower Passaic River Study Area (LPRSA)) in New Jersey as a “superfund” site requiring environmental remediation and has identified certain Potentially Responsible Parties (PRPs), including PSEG. The EPA has released a Record of Decision (ROD) for the LPRSA’s lower 8.3 miles that requires the removal of sediments at an estimated cost of $2.3 billion
(ROD Remedy). An EPA-commenced process to allocate the associated costs to the PRPs is underway, and PSEG cannot predict the outcome. Additionally, one of the PRPs has filed suit against PSEG and others seeking cost recovery and contribution under the Federal Comprehensive Environmental Response, Compensation and Liability Act of 1980, but has not quantified alleged damages. The litigation is ongoing and PSEG cannot predict the outcome. As of December 31, 2020, PSEG recorded an environmental liability of $65 million for its estimated share of the remediation of the environmental contamination, a portion of which has been deferred as a regulatory asset based on PSEG’s assessment that PSE&G will recover such costs in future rates.
The outcome of this matter is uncertain, and PSEG cannot predict this matter’s ultimate impact on its financial statements. It is possible that PSEG will record additional costs beyond what it has accrued, and that such costs could be material, but PSEG cannot at the current time estimate the amount or range of any additional costs.
We identified the accounting for the Passaic River environmental liability as a critical audit matter due to the uncertainties inherent in estimating PSEG’s liability. Auditing PSEG’s estimated share of the remediation cost, the environmental liability recorded, and the evaluation of future recovery of the regulatory asset recorded required a high degree of auditor judgment and the involvement of our environmental specialists.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the Passaic River environmental liability included the following, among others:
•We tested the effectiveness of controls over the Passaic River environmental liability, including those over the evaluation of recent events and changes in circumstances that have or may give rise to a change in PSEG’s estimated share of the total remediation costs.
•We tested the effectiveness of controls over the Passaic River regulatory asset, including controls over the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering the Passaic River regulatory asset in future rates.
•With the assistance of our environmental specialists, we evaluated publicly available information regarding the status of the Passaic River superfund site, including planned remediation techniques and associated estimated costs, and compared this to information used in management’s estimate of the environmental liability.
•We evaluated the assumptions used by management to estimate PSEG’s share of the environmental obligation, including consideration of publicly available information.
•We requested and received a written response from internal counsel and external legal firms representing PSEG and evaluated the legal conclusions for consistency with those used in management’s accounting judgments and disclosures.
•We evaluated management’s analysis over the assertion that the Passaic River regulatory asset is probable of recovery.
•We evaluated the related disclosures for consistency with our understanding.
/s/ DELOITTE & TOUCHE LLP
Parsippany, New Jersey
February 26, 2021
We have served as the Company's auditor since 1934.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Sole Stockholder of
Public Service Electric and Gas Company
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Public Service Electric and Gas Company and subsidiaries (the “Company” or PSE&G) as of December 31, 2020 and 2019, the related consolidated statements of operations, comprehensive income, common stockholder’s equity, and cash flows, for each of the three years in the period ended December 31, 2020, the related notes and the consolidated financial statement schedule listed in the Index at Item 15(B)(b) (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2020 and 2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2020, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matters
The critical audit matters communicated below are matters arising from the current-period audit of the financial statements that were communicated or required to be communicated to the audit committee and that (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.
Regulatory Assets and Liabilities - Income Taxes -Refer to Notes 1, 7, and 22 to the financial statements
Critical Audit Matter Description
PSE&G’s electric and gas transmission and distribution businesses are regulated by the Board of Public Utilities (BPU) and Federal Energy Regulatory Commission. Management believes that PSE&G’s transmission and distribution businesses continue to meet the accounting requirements for rate-regulated entities, and PSE&G’s financial statements reflect the economic effects of cost-based rate regulation. Through the rate-making process, PSE&G’s rates to customers also include the recovery of income tax expense associated with PSE&G’s electric and gas distribution and electric transmission operations. PSE&G has recorded regulatory liabilities for excess accumulated deferred income taxes (ADIT) which will be refunded to customers in future periods. PSE&G’s most recent electric and gas distribution base rate case, concluded in 2018, established the Tax Adjustment Credit (TAC) that provides for the refund of these excess ADIT regulatory liabilities as well as the flow through to customers of historical and current accumulated deferred income taxes for tax-deductible repairs. The flow through of the current tax benefits results in lower revenues and lower income tax expense, as well as the recognition of a regulatory asset as management believes it is probable that the accumulated tax benefits treated as a flow-through item to PSE&G customers will be recovered from customers in the future.
We identified the accounting for the TAC as a critical audit matter due to the complexity in accounting for the impact of rate regulation on income tax expense. Auditing management’s assertion that the TAC regulatory assets are probable of future recovery, and that the accounting for the TAC is accurately recorded and reported, requires auditor judgment and specialized knowledge of accounting matters specific to rate regulation. Further, the determination of the estimated benefit of current tax-deductible repairs under the Internal Revenue Code, and the resulting impacts on the TAC regulatory asset and income tax expense recorded in the financial statements, is complex, and required a high degree of auditor judgment and the involvement of our income tax specialists.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures to evaluate PSE&G’s accounting for the TAC and the associated regulatory assets, regulatory liabilities, and income tax expense included the following, among others:
• We tested the effectiveness of controls over the calculation of the amounts refunded through the TAC, including controls over the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering the TAC regulatory asset in future rates.
• We evaluated management’s analysis over the assertion that the TAC regulatory assets are probable of recovery.
• We evaluated relevant regulatory orders related to the ratemaking treatment of income taxes.
• With the assistance of our income tax specialists, we tested the accuracy of income tax expense, regulatory assets and regulatory liabilities associated with the TAC.
• We evaluated the financial statement presentation and related disclosures for consistency with our understanding.
Commitments and Contingent Liabilities - Passaic River Environmental Liability - Refer to Note 15 to the financial statements
Critical Audit Matter Description
As described in Note 15, the U.S. Environmental Protection Agency (EPA) has designated a 17-mile stretch of the lower Passaic River (Lower Passaic River Study Area (LPRSA)) in New Jersey as a “superfund” site requiring environmental remediation and has identified certain Potentially Responsible Parties (PRPs), including PSE&G. The EPA has released a Record of Decision (ROD) for the LPRSA’s lower 8.3 miles that requires the removal of sediments at an estimated cost of $2.3 billion (ROD Remedy). An EPA-commenced process to allocate the associated costs to the PRPs is underway, and PSE&G cannot predict the outcome. Additionally, one of the PRPs has filed suit against PSE&G and others seeking cost recovery and contribution under the Federal Comprehensive Environmental Response, Compensation and Liability Act of 1980, but has not quantified alleged damages. The litigation is ongoing and PSE&G cannot predict the outcome. As of December 31, 2020, PSE&G recorded an environmental liability of $52 million for its estimated share of the remediation of the environmental contamination, and a corresponding regulatory asset based on PSE&G’s assessment that it will recover such costs in future rates.
The outcome of this matter is uncertain, and PSE&G cannot predict this matter’s ultimate impact on its financial statements. It is possible that PSE&G will record additional costs beyond what it has accrued, and that such costs could be material, but PSE&G cannot at the current time estimate the amount or range of any additional costs.
We identified the accounting for the Passaic River environmental liability as a critical audit matter due to the uncertainties inherent in estimating PSE&G’s liability. Auditing PSE&G’s estimated share of the remediation cost, the environmental liability recorded, and the evaluation of future recovery of the regulatory asset recorded required a high degree of auditor judgment and the involvement of our environmental specialists.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the Passaic River environmental liability included the following, among others:
• We tested the effectiveness of controls over the Passaic River environmental liability, including those over the evaluation of recent events and changes in circumstances that have or may give rise to a change in PSE&G’s estimated share of the total remediation costs.
• We tested the effectiveness of controls over the Passaic River regulatory asset, including controls over the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering the Passaic River regulatory asset in future rates.
• With the assistance of our environmental specialists, we evaluated publicly available information regarding the status of the Passaic River superfund site, including planned remediation techniques and associated estimated costs, and compared this to information used in management’s estimate of the environmental liability.
• We evaluated the assumptions used by management to estimate PSE&G’s share of the environmental obligation, including consideration of publicly available information.
• We requested and received a written response from external legal firms representing PSE&G and evaluated the legal conclusions for consistency with those used in management’s accounting judgments and disclosures.
• We evaluated management’s analysis over the assertion that the Passaic River regulatory asset is probable of recovery.
• We evaluated the related disclosures for consistency with our understanding.
/s/ DELOITTE & TOUCHE LLP
Parsippany, New Jersey
February 26, 2021
We have served as the Company's auditor since 1934.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Sole Member of
PSEG Power LLC
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of PSEG Power LLC and subsidiaries (the “Company” or PSEG Power) as of December 31, 2020 and 2019, the related consolidated statements of operations, comprehensive income, member’s equity, and cash flows, for each of the three years in the period ended December 31, 2020, the related notes and the consolidated financial statement schedule listed in the Index at Item 15(B)(c) (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2020 and 2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2020, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matters
The critical audit matters communicated below are matters arising from the current-period audit of the financial statements that were communicated or required to be communicated to the audit committee and that (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.
Early Plant Retirements - Nuclear - Refer to Notes 4 and 13 to the financial statements
Critical Audit Matter Description
PSEG Power owns and operates nuclear plants in New Jersey and has recorded associated asset retirement obligations (ARO) for their eventual decommissioning. In April 2019, the New Jersey Board of Public Utilities (BPU) awarded Zero Emission Certificates (ZEC) to PSEG Power’s Salem 1, Salem 2 and Hope Creek nuclear plants for an initial period of approximately three years through May 2022. The initial ZEC award has been appealed by the New Jersey Rate Counsel and PSEG Power cannot predict the outcome of this matter. In October 2020, PSEG Power filed its application for the second eligibility period beginning in June 2022.
In the event that (i) the ZEC program is overturned or is otherwise materially adversely modified through legal process; (ii) the amount of ZEC payments that may be awarded or other terms and conditions of the second ZEC eligibility period proposed by the BPU in its final decision differ from those of the current ZEC period; or (iii) any of the Salem 1, Salem 2 and Hope Creek plants is not awarded ZEC payments by the BPU and does not otherwise experience a material financial change, PSEG Power has disclosed that it will take all necessary steps to cease to operate these nuclear plants. This would result in material charges associated with accelerated depreciation and amortization, impairment charges, and accelerated asset retirement costs, among other costs.
We identified the potential early retirement of the nuclear plants as a critical audit matter because of the significant estimates and assumptions management made in determining the useful lives of the nuclear plants and in evaluating the recorded investments in the nuclear plants for potential impairment. Further, management’s estimates used in recording the ARO included a number of assumptions, including the timing of cash flows associated with the eventual decommissioning of the nuclear plants following the retirement of the assets. Auditing each of these assumptions required a high degree of auditor judgment.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the potential early retirement of the nuclear plants and the related impact on the recorded investments in the nuclear plants and the related ARO included the following, among others:
•We tested the effectiveness of controls over the evaluation of potential impairment indicators, including management’s consideration of legal and regulatory matters related to ZECs.
•We tested the effectiveness of controls over the evaluation of retirement date assumptions used in the calculation of the ARO, including the probability weighting of the various cash flow scenarios.
•We evaluated management’s judgments over the probability of early retirement of the nuclear plants and impairment triggers including considerations of regulatory matters for the second ZEC eligibility period.
•We evaluated management’s assumptions over the weighted-probability of early retirement of the nuclear plants used in calculating the recorded nuclear ARO balance.
•We requested and received written response from internal counsel and external legal firms representing PSEG Power and evaluated the legal conclusions for consistency with those used in management’s accounting judgments and disclosures.
•We obtained written representations from management regarding their intent to cease to operate the nuclear plants in the event that certain legal, regulatory, and economic matters are not favorably resolved.
•We evaluated the related disclosures for consistency with our understanding.
Asset Dispositions - Potential Sale of Non-Nuclear Assets - Impairment Tests - Refer to Note 4 to the financial statements
Critical Audit Matter Description
In July 2020, PSEG Power announced that it is exploring strategic alternatives for its non-nuclear generating fleet, which includes more than 6,750 MW of fossil generation located in New Jersey, Connecticut, New York and Maryland. As a result, PSEG Power performed impairment tests for its portfolio of assets in the PJM, NYISO and NEPOOL regions. The assessments included probability weightings assigned to undiscounted cash flow scenarios of retaining the assets through their estimated useful lives and a potential disposition of the assets. As of December 31, 2020, the estimated undiscounted future cash flows of each of the asset groups exceeded the carrying amount and no impairment was identified.
We identified the impairment tests over the PJM, NYISO and NEPOOL asset groupings as a critical audit matter because of the significant management judgements and estimates related to asset grouping conclusions, the probability weighting of the outcomes of various scenarios, and the significant inputs utilized in the impairment test to determine the estimated undiscounted cash flows. Those inputs include estimated forward power prices, fuel costs and dispatch rates as well as estimates of fair value to be received upon any disposition of assets. Auditing these estimates and assumptions required a high degree of auditor judgment and the involvement of our fair value specialists.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the impairment tests over the PJM, NYISO and NEPOOL asset groupings included the following, among others:
•We tested the effectiveness of controls over management’s impairment tests including considerations of asset groupings, the significant inputs utilized to determine estimated undiscounted cash flows, and the weighted probabilities assigned to the outcome of various scenarios.
•We evaluated management’s conclusions regarding the asset groupings utilized for the purposes of the impairment tests.
•With the assistance of our fair value specialists, we evaluated the significant inputs utilized within management’s impairment tests including forward power prices, fuel costs, dispatch rates and estimates of the fair value to be
received upon any disposition of assets.
•We evaluated management’s assumptions related to the weighted probabilities assigned to the outcome of various scenarios.
•We evaluated the related disclosures for consistency with our understanding.
Commitments and Contingent Liabilities - Passaic River Environmental Liability - Refer to Note 15 to the financial statements
Critical Audit Matter Description
As described in Note 15, the U.S. Environmental Protection Agency (EPA) has designated a 17-mile stretch of the lower Passaic River (Lower Passaic River Study Area (LPRSA)) in New Jersey as a “superfund” site requiring environmental remediation and has identified certain potentially responsible parties (PRPs), including PSEG Power. The EPA has released a Record of Decision (ROD) for the LPRSA’s lower 8.3 miles that requires the removal of sediments at an estimated cost of $2.3 billion (ROD Remedy). An EPA-commenced process to allocate the associated costs to the PRPs is underway, and PSEG Power cannot predict the outcome. Additionally, one of the PRPs has filed suit against PSEG Power and others seeking cost recovery and contribution under the Federal Comprehensive Environmental Response, Compensation and Liability Act of 1980, but has not quantified alleged damages. The litigation is ongoing and PSEG Power cannot predict the outcome. As of December 31, 2020, PSEG Power recorded an environmental liability of $13 million for its estimated share of the remediation of the environmental contamination.
The outcome of this matter is uncertain, and PSEG Power cannot predict this matter’s ultimate impact on its financial statements. It is possible that PSEG Power will record additional costs beyond what it has accrued, and that such costs could be material, but PSEG Power cannot at the current time estimate the amount or range of any additional costs.
We identified the accounting for the Passaic River environmental liability as a critical audit matter due to the uncertainties inherent in estimating PSEG Power’s liability. Auditing PSEG Power’s estimated share of the remediation cost and the environmental liability recorded required a high degree of auditor judgment and the involvement of our environmental specialists.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the Passaic River environmental liability included the following, among others:
•We tested the effectiveness of controls over the Passaic River environmental liability, including those over the evaluation of recent events and changes in circumstances that have or may give rise to a change in PSEG Power’s estimated share of the total remediation costs.
•With the assistance of our environmental specialists, we evaluated publicly available information regarding the status of the Passaic River superfund site, including planned remediation techniques and associated estimated costs, and compared this to information used in management’s estimate of the environmental liability.
•We evaluated the assumptions used by management to estimate PSEG Power’s share of the environmental obligation, including consideration of publicly available information.
•We requested and received a written response from internal counsel and external legal firms representing PSEG Power and evaluated the legal conclusions for consistency with those used in management’s accounting judgments and disclosures.
•We evaluated the related disclosures for consistency with our understanding.
/s/ DELOITTE & TOUCHE LLP
Parsippany, New Jersey
February 26, 2021
We have served as the Company's auditor since 2000.
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONSOLIDATED STATEMENTS OF OPERATIONS
Millions, except per share data
Years Ended December 31,
2020 2019 2018
OPERATING REVENUES $ 9,603 $ 10,076 $ 9,696
OPERATING EXPENSES
Energy Costs 3,056 3,372 3,225
Operation and Maintenance 3,115 3,111 3,069
Depreciation and Amortization 1,285 1,248 1,158
(Gain) Loss on Asset Dispositions (123) 402 (54)
Total Operating Expenses 7,333 8,133 7,398
OPERATING INCOME 2,270 1,943 2,298
Income from Equity Method Investments 14 14 15
Net Gains (Losses) on Trust Investments 253 260 (143)
Other Income (Deductions) 115 125 85
Non-Operating Pension and OPEB Credits (Costs) 249 177 76
Interest Expense (600) (569) (476)
INCOME BEFORE INCOME TAXES 2,301 1,950 1,855
Income Tax Benefit (Expense) (396) (257) (417)
NET INCOME $ 1,905 $ 1,693 $ 1,438
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:
BASIC 504 504 504
DILUTED 507 507 507
NET INCOME PER SHARE:
BASIC $ 3.78 $ 3.35 $ 2.85
DILUTED $ 3.76 $ 3.33 $ 2.83
See Notes to Consolidated Financial Statements.
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Millions
Years Ended December 31,
2020 2019 2018
NET INCOME $ 1,905 $ 1,693 $ 1,438
Other Comprehensive Income (Loss), net of tax
Unrealized Gains (Losses) on Available-for-Sale Securities, net of tax (expense) benefit of $(16), $(26) and $11 for the years ended 2020, 2019 and 2018, respectively
25 41 (17)
Unrealized Gains (Losses) on Cash Flow Hedges, net of tax (expense) benefit of $(2), $6 and $1 for the years ended 2020, 2019 and 2018, respectively
6 (14) (1)
Pension/OPEB adjustment, net of tax (expense) benefit of $18, $18 and $(18) for the years ended 2020, 2019 and 2018, respectively
(46) (58) 46
Other Comprehensive Income (Loss), net of tax (15) (31) 28
COMPREHENSIVE INCOME $ 1,890 $ 1,662 $ 1,466
See Notes to Consolidated Financial Statements.
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONSOLIDATED BALANCE SHEETS
Millions
December 31,
2020 2019
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents $ 543 $ 147
Accounts Receivable, net of allowance of $196 in 2020 and $60 in 2019
1,410 1,313
Tax Receivable 63 21
Unbilled Revenues, net of allowance of $10 in 2020
229 239
Fuel 277 310
Materials and Supplies, net 601 587
Prepayments 51 79
Derivative Contracts 60 113
Regulatory Assets 369 351
Assets Held for Sale - 30
Other 27 41
Total Current Assets 3,630 3,231
PROPERTY, PLANT AND EQUIPMENT 48,569 45,944
Less: Accumulated Depreciation and Amortization
(10,984) (10,100)
Net Property, Plant and Equipment
37,585 35,844
NONCURRENT ASSETS
Regulatory Assets 3,872 3,677
Operating Lease Right-of-Use Assets 262 282
Long-Term Investments 536 812
Nuclear Decommissioning Trust (NDT) Fund 2,501 2,216
Long-Term Tax Receivable - 150
Long-Term Receivable of Variable Interest Entity 945 813
Rabbi Trust Fund 266 246
Other Intangibles 158 149
Derivative Contracts 9 24
Other 286 286
Total Noncurrent Assets 8,835 8,655
TOTAL ASSETS $ 50,050 $ 47,730
See Notes to Consolidated Financial Statements.
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONSOLIDATED BALANCE SHEETS
Millions
December 31,
2020 2019
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES
Long-Term Debt Due Within One Year $ 1,684 $ 1,365
Commercial Paper and Loans 1,063 1,115
Accounts Payable 1,332 1,358
Derivative Contracts 21 36
Accrued Interest 126 116
Accrued Taxes 124 41
Clean Energy Program 143 143
Obligation to Return Cash Collateral 98 119
Regulatory Liabilities 294 234
Other 637 520
Total Current Liabilities 5,522 5,047
NONCURRENT LIABILITIES
Deferred Income Taxes and Investment Tax Credits (ITC) 6,502 6,256
Regulatory Liabilities 2,707 3,002
Operating Leases 252 273
Asset Retirement Obligations 1,212 1,087
Other Postretirement Benefit (OPEB) Costs 730 734
OPEB Costs of Servco 699 626
Accrued Pension Costs 1,128 952
Accrued Pension Costs of Servco 226 171
Environmental Costs 286 349
Derivative Contracts 4 1
Long-Term Accrued Taxes 88 182
Other 214 218
Total Noncurrent Liabilities 14,048 13,851
COMMITMENTS AND CONTINGENT LIABILITIES (See Note 15)
CAPITALIZATION
LONG-TERM DEBT
14,496 13,743
STOCKHOLDERS’ EQUITY
Common Stock, no par, authorized 1,000 shares; issued, 2020 and 2019-534 shares
5,031 5,003
Treasury Stock, at cost, 2020 and 2019-30 shares
(861) (831)
Retained Earnings 12,318 11,406
Accumulated Other Comprehensive Loss (504) (489)
Total Stockholders’ Equity 15,984 15,089
Total Capitalization 30,480 28,832
TOTAL LIABILITIES AND CAPITALIZATION $ 50,050 $ 47,730
See Notes to Consolidated Financial Statements.
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONSOLIDATED STATEMENTS OF CASH FLOWS
Millions
Years Ended December 31,
2020 2019 2018
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income $ 1,905 $ 1,693 $ 1,438
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization 1,285 1,248 1,158
Amortization of Nuclear Fuel 184 178 187
(Gain) Loss on Asset Dispositions (123) 402 (54)
Emission Allowances and Renewable Energy Credit (REC) Compliance Accrual 151 108 97
Provision for Deferred Income Taxes (Other than Leases) and ITC 139 180 568
Non-Cash Employee Benefit Plan (Credits) Costs (105) (48) 70
Leveraged Lease (Income), (Gains) and Losses, Adjusted for Rents Received and Deferred Taxes (135) 18 (144)
Net Realized and Unrealized (Gains) Losses on Energy Contracts and Other Derivatives 80 (290) 116
Cost of Removal (106) (108) (160)
Net Change in Regulatory Assets and Liabilities (101) 25 (153)
Net (Gains) Losses and (Income) Expense from NDT Fund (278) (296) 98
Net Change in Certain Current Assets and Liabilities:
Tax Receivable 107 77 17
Accrued Taxes 124 (9) (69)
Cash Collateral (10) 349 (247)
Other Current Assets and Liabilities 73 (145) 70
Employee Benefit Plan Funding and Related Payments (18) (39) (101)
Other (70) 36 22
Net Cash Provided By (Used In) Operating Activities 3,102 3,379 2,913
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment (2,923) (3,166) (3,912)
Purchase of Emissions Allowances and RECs (111) (98) (146)
Proceeds from Sales of Trust Investments 2,234 1,787 1,501
Purchases of Trust Investments (2,250) (1,814) (1,473)
Proceeds from Sales of Long-Lived Assets and Lease Investments 301 70 31
Other 73 76 83
Net Cash Provided By (Used In) Investing Activities (2,676) (3,145) (3,916)
CASH FLOWS FROM FINANCING ACTIVITIES
Net Change in Commercial Paper and Loans (352) 99 474
Proceeds from Short-Term Loan 800 - -
Repayment of Short-Term Loans (500) - -
Issuance of Long-Term Debt 2,450 1,900 2,750
Redemption of Long-Term Debt (1,365) (1,250) (1,350)
Cash Dividends Paid on Common Stock (991) (950) (910)
Other (72) (56) (77)
Net Cash Provided By (Used In) Financing Activities (30) (257) 887
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash 396 (23) (116)
Cash, Cash Equivalents and Restricted Cash at Beginning of Period 176 199 315
Cash, Cash Equivalents and Restricted Cash at End of Period $ 572 $ 176 $ 199
Supplemental Disclosure of Cash Flow Information:
Income Taxes Paid (Received) $ 297 $ 41 $ 99
Interest Paid, Net of Amounts Capitalized $ 568 $ 539 $ 454
Accrued Property, Plant and Equipment Expenditures $ 387 $ 499 $ 517
See Notes to Consolidated Financial Statements.
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
Millions
Common
Stock Treasury
Stock Retained
Earnings Accumulated
Other
Comprehensive
Income (Loss)
Shs. Amount Shs. Amount Total
Balance as of December 31, 2017 534 $ 4,961 (29) $ (763) $ 9,878 $ (229) $ 13,847
Net Income - - - - 1,438 - 1,438
Cumulative Effect Adjustment to Reclassify Unrealized Net Gains on Equity Investments - - - - 176 (176) -
Other Comprehensive Income (Loss), net of tax (expense) benefit of $(6)
- - - - - 28 28
Comprehensive Income 1,466
Cash Dividends at $1.80 per share on Common Stock
- - - - (910) - (910)
Other - 19 (1) (45) - - (26)
Balance as of December 31, 2018 534 $ 4,980 (30) $ (808) $ 10,582 $ (377) $ 14,377
Net Income - - - - 1,693 - 1,693
Cumulative Effect Adjustment to Reclassify Stranded Tax Effects Resulting in the Change in the Federal Corporate Income Tax Rate - - - - 81 (81) -
Other Comprehensive Income (Loss), net of tax (expense) benefit of $(2)
- - - - - (31) (31)
Comprehensive Income 1,662
Cash Dividends at $1.88 per share on Common Stock
- - - - (950) - (950)
Other - 23 - (23) - - -
Balance as of December 31, 2019 534 $ 5,003 (30) $ (831) $ 11,406 $ (489) $ 15,089
Net Income - - - - 1,905 - 1,905
Other Comprehensive Income (Loss), net of tax (expense) benefit of $0
- - - - - (15) (15)
Comprehensive Income 1,890
Cumulative Effect Adjustment for Current Expected Credit Losses (CECL) - - - - (2) - (2)
Cash Dividends at $1.96 per share on Common Stock
- - - - (991) - (991)
Other - 28 - (30) - - (2)
Balance as of December 31, 2020 534 $ 5,031 (30) $ (861) $ 12,318 $ (504) $ 15,984
See Notes to Consolidated Financial Statements.
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
Millions
Years Ended December 31,
2020 2019 2018
OPERATING REVENUES $ 6,608 $ 6,625 $ 6,471
OPERATING EXPENSES
Energy Costs 2,469 2,738 2,520
Operation and Maintenance 1,614 1,581 1,575
Depreciation and Amortization 887 837 770
Gain on Asset Dispositions (1) - -
Total Operating Expenses 4,969 5,156 4,865
OPERATING INCOME 1,639 1,469 1,606
Net Gains (Losses) on Trust Investments 3 2 (1)
Other Income (Deductions) 108 83 80
Non-Operating Pension and OPEB Credits (Costs) 205 150 59
Interest Expense (388) (361) (333)
INCOME BEFORE INCOME TAXES 1,567 1,343 1,411
Income Tax Benefit (Expense) (240) (93) (344)
NET INCOME $ 1,327 $ 1,250 $ 1,067
See disclosures regarding Public Service Electric and Gas Company included in the Notes to Consolidated Financial Statements.
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Millions
Years Ended December 31,
2020 2019 2018
NET INCOME $ 1,327 $ 1,250 $ 1,067
Other Comprehensive Income (Loss), net of tax
Unrealized Gains (Losses) on Available-for-Sale Securities, net of tax (expense) benefit of $0, $(1) and $1 for the years ended 2020, 2019 and 2018, respectively
1 3 (1)
COMPREHENSIVE INCOME $ 1,328 $ 1,253 $ 1,066
See disclosures regarding Public Service Electric and Gas Company included in the Notes to Consolidated Financial Statements.
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
CONSOLIDATED BALANCE SHEETS
Millions
December 31,
2020 2019
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents $ 204 $ 21
Accounts Receivable, net of allowance of $196 in 2020 and $60 in 2019
1,004 901
Accounts Receivable-Affiliated Companies - 1
Unbilled Revenues, net of allowance of $10 in 2020
229 239
Materials and Supplies, net 217 213
Prepayments 14 35
Regulatory Assets 369 351
Other 13 28
Total Current Assets 2,050 1,789
PROPERTY, PLANT AND EQUIPMENT 36,300 33,900
Less: Accumulated Depreciation and Amortization
(7,149) (6,623)
Net Property, Plant and Equipment 29,151 27,277
NONCURRENT ASSETS
Regulatory Assets 3,872 3,677
Operating Lease Right-of-Use Assets 99 98
Long-Term Investments 222 248
Rabbi Trust Fund 51 48
Other 136 129
Total Noncurrent Assets 4,380 4,200
TOTAL ASSETS $ 35,581 $ 33,266
See disclosures regarding Public Service Electric and Gas Company included in the Notes to Consolidated Financial Statements.
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
CONSOLIDATED BALANCE SHEETS
Millions
December 31,
2020 2019
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES
Long-Term Debt Due Within One Year $ 434 $ 259
Commercial Paper and Loans 100 362
Accounts Payable 671 639
Accounts Payable-Affiliated Companies 479 390
Accrued Interest 101 91
Clean Energy Program 143 143
Obligation to Return Cash Collateral 98 119
Regulatory Liabilities 294 234
Other 530 436
Total Current Liabilities 2,850 2,673
NONCURRENT LIABILITIES
Deferred Income Taxes and ITC 4,524 4,189
Regulatory Liabilities 2,707 3,002
Operating Leases 88 87
Asset Retirement Obligations 314 303
OPEB Costs 485 495
Accrued Pension Costs 612 501
Environmental Costs 236 294
Long-Term Accrued Taxes 7 115
Other 154 136
Total Noncurrent Liabilities 9,127 9,122
COMMITMENTS AND CONTINGENT LIABILITIES (See Note 15)
CAPITALIZATION
LONG-TERM DEBT 10,475 9,568
STOCKHOLDER’S EQUITY
Common Stock; 150 shares authorized; issued and outstanding, 2020 and 2019-132 shares
892 892
Contributed Capital 1,170 1,095
Basis Adjustment 986 986
Retained Earnings 10,078 8,928
Accumulated Other Comprehensive Income (Loss) 3 2
Total Stockholder’s Equity 13,129 11,903
Total Capitalization 23,604 21,471
TOTAL LIABILITIES AND CAPITALIZATION $ 35,581 $ 33,266
See disclosures regarding Public Service Electric and Gas Company included in the Notes to Consolidated Financial Statements.
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
Millions
Years Ended December 31,
2020 2019 2018
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income $ 1,327 $ 1,250 $ 1,067
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization 887 837 770
Provision for Deferred Income Taxes and ITC 53 (28) 405
Non-Cash Employee Benefit Plan (Credits) Costs (103) (62) 37
Cost of Removal (106) (108) (160)
Net Change in Other Regulatory Assets and Liabilities (101) 25 (153)
Net Change in Certain Current Assets and Liabilities
Accounts Receivable and Unbilled Revenues (100) (18) 65
Materials and Supplies (2) (14) 1
Prepayments 21 (9) 14
Accounts Payable 44 (59) 64
Accounts Receivable/Payable-Affiliated Companies, net 80 203 (139)
Other Current Assets and Liabilities 60 62 5
Employee Benefit Plan Funding and Related Payments (4) (21) (85)
Other (103) (23) (38)
Net Cash Provided By (Used In) Operating Activities 1,953 2,035 1,853
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment (2,507) (2,542) (2,896)
Proceeds from Sales of Trust Investments 40 36 20
Purchases of Trust Investments (40) (34) (22)
Solar Loan Investments 13 8 (5)
Other 12 10 9
Net Cash Provided By (Used In) Investing Activities (2,482) (2,522) (2,894)
CASH FLOWS FROM FINANCING ACTIVITIES
Net Change in Commercial Paper and Loans (262) 90 272
Issuance of Long-Term Debt 1,350 1,150 1,350
Redemption of Long-Term Debt (259) (500) (750)
Contributed Capital 75 - -
Cash Dividend Paid (175) (250) -
Other (17) (14) (14)
Net Cash Provided By (Used In) Financing Activities 712 476 858
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash 183 (11) (183)
Cash, Cash Equivalents and Restricted Cash at Beginning of Period 50 61 244
Cash, Cash Equivalents and Restricted Cash at End of Period $ 233 $ 50 $ 61
Supplemental Disclosure of Cash Flow Information:
Income Taxes Paid (Received) $ 157 $ (48) $ 94
Interest Paid, Net of Amounts Capitalized $ 369 $ 343 $ 318
Accrued Property, Plant and Equipment Expenditures $ 323 $ 335 $ 350
See disclosures regarding Public Service Electric and Gas Company included in the Notes to Consolidated Financial Statements.
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER’S EQUITY
Millions
Common Stock Contributed
Capital Basis
Adjustment Retained
Earnings Accumulated
Other
Comprehensive
Income (Loss) Total
Balance as of December 31, 2017 $ 892 $ 1,095 $ 986 $ 6,861 $ - $ 9,834
Net Income - - - 1,067 - 1,067
Other Comprehensive Income (Loss), net of tax (expense) benefit of $1
- - - - (1) (1)
Comprehensive Income 1,066
Balance as of December 31, 2018 $ 892 $ 1,095 $ 986 $ 7,928 $ (1) $ 10,900
Net Income - - - 1,250 - 1,250
Other Comprehensive Income (Loss), net of tax (expense) benefit of $(1)
- - - - 3 3
Comprehensive Income 1,253
Cash Dividends Paid - - - (250) - (250)
Balance as of December 31, 2019 $ 892 $ 1,095 $ 986 $ 8,928 $ 2 $ 11,903
Net Income - - - 1,327 - 1,327
Other Comprehensive Income (Loss), net of tax (expense) benefit of $0
- - - - 1 1
Comprehensive Income 1,328
Cumulative Effect Adjustment for CECL - - - (2) - (2)
Cash Dividends Paid - - - (175) - (175)
Contributed Capital - 75 - - - 75
Balance as of December 31, 2020 $ 892 $ 1,170 $ 986 $ 10,078 $ 3 $ 13,129
See disclosures regarding Public Service Electric and Gas Company included in the Notes to Consolidated Financial Statements.
PSEG POWER LLC
CONSOLIDATED STATEMENTS OF OPERATIONS
Millions
Years Ended December 31,
2020 2019 2018
OPERATING REVENUES $ 3,634 $ 4,385 $ 4,146
OPERATING EXPENSES
Energy Costs 1,821 2,118 2,197
Operation and Maintenance 964 1,040 1,053
Depreciation and Amortization 368 377 354
(Gain) Loss on Asset Dispositions (122) 402 (54)
Total Operating Expenses 3,031 3,937 3,550
OPERATING INCOME 603 448 596
Income from Equity Method Investments 14 14 15
Net Gains (Losses) on Trust Investments 241 253 (140)
Other Income (Deductions) 12 54 21
Non-Operating Pension and OPEB (Costs) Credits 33 21 15
Interest Expense (121) (119) (76)
INCOME BEFORE INCOME TAXES 782 671 431
Income Tax Benefit (Expense) (188) (203) (66)
NET INCOME $ 594 $ 468 $ 365
See disclosures regarding PSEG Power LLC included in the Notes to Consolidated Financial Statements.
PSEG POWER LLC
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Millions
Years Ended December 31,
2020 2019 2018
NET INCOME $ 594 $ 468 $ 365
Other Comprehensive Income (Loss), net of tax
Unrealized Gains (Losses) on Available-for-Sale Securities, net of tax (expense) benefit of $(15), $(22) and $9 for the years ended 2020, 2019 and 2018, respectively
21 32 (13)
Pension/OPEB adjustment, net of tax (expense) benefit of $16, $13 and $(16) for the years ended 2020, 2019 and 2018, respectively
(39) (45) 41
Other Comprehensive Income (Loss), net of tax (18) (13) 28
COMPREHENSIVE INCOME $ 576 $ 455 $ 393
See disclosures regarding PSEG Power LLC included in the Notes to Consolidated Financial Statements.
PSEG POWER LLC
CONSOLIDATED BALANCE SHEETS
Millions
December 31,
2020 2019
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents $ 27 $ 21
Accounts Receivable 328 309
Accounts Receivable-Affiliated Companies 317 408
Short-Term Loan to Affiliate 161 149
Fuel 277 310
Materials and Supplies, net 382 372
Derivative Contracts 60 113
Prepayments 16 11
Assets Held for Sale - 28
Other 2 5
Total Current Assets 1,570 1,726
PROPERTY, PLANT AND EQUIPMENT 11,872 11,699
Less: Accumulated Depreciation and Amortization (3,624) (3,273)
Net Property, Plant and Equipment 8,248 8,426
NONCURRENT ASSETS
Operating Lease Right-of-Use Assets 61 71
NDT Fund 2,501 2,216
Long-Term Investments 64 66
Other Intangibles 158 149
Rabbi Trust Fund 66 62
Derivative Contracts 9 24
Other 27 65
Total Noncurrent Assets 2,886 2,653
TOTAL ASSETS $ 12,704 $ 12,805
See disclosures regarding PSEG Power LLC included in the Notes to Consolidated Financial Statements.
PSEG POWER LLC
CONSOLIDATED BALANCE SHEETS
Millions
December 31,
2020 2019
LIABILITIES AND MEMBER’S EQUITY
CURRENT LIABILITIES
Long-Term Debt Due Within One Year $ 950 $ 406
Accounts Payable 459 505
Accounts Payable-Affiliated Companies 13 5
Derivative Contracts 21 31
Accrued Interest 16 21
Other 101 91
Total Current Liabilities 1,560 1,059
NONCURRENT LIABILITIES
Deferred Income Taxes and ITC 1,936 1,876
Operating Leases 51 62
Asset Retirement Obligations 895 781
OPEB Costs 197 192
Accrued Pension Costs 321 284
Derivative Contracts 4 1
Long-Term Accrued Taxes 57 115
Other 79 111
Total Noncurrent Liabilities 3,540 3,422
COMMITMENTS AND CONTINGENT LIABILITIES (See Note 15)
LONG-TERM DEBT
1,392 2,434
MEMBER’S EQUITY
Contributed Capital 2,310 2,214
Basis Adjustment (986) (986)
Retained Earnings 5,307 5,063
Accumulated Other Comprehensive Loss (419) (401)
Total Member’s Equity 6,212 5,890
TOTAL LIABILITIES AND MEMBER’S EQUITY $ 12,704 $ 12,805
See disclosures regarding PSEG Power LLC included in the Notes to Consolidated Financial Statements.
PSEG POWER LLC
CONSOLIDATED STATEMENTS OF CASH FLOWS
Millions
Years Ended December 31,
2020 2019 2018
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income $ 594 $ 468 $ 365
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization 368 377 354
Amortization of Nuclear Fuel 184 178 187
(Gain) Loss on Asset Dispositions (122) 402 (54)
Emission Allowances and Renewable Energy Credit (REC) Compliance Accrual 151 108 97
Provision for Deferred Income Taxes and ITC 60 248 206
Non-Cash Employee Benefit Plan Costs (5) 7 23
Interest Accretion on Asset Retirement Obligation 42 40 41
Net Realized and Unrealized (Gains) Losses on Energy Contracts and Other Derivatives 80 (290) 116
Net (Gains) Losses and (Income) Expense from NDT Fund (278) (296) 98
Net Change in Certain Current Assets and Liabilities
Fuel, Materials and Supplies 18 (1) (39)
Cash Collateral (10) 349 (247)
Accounts Receivable 19 (32) 51
Accounts Payable (23) 5 (13)
Accounts Receivable/Payable-Affiliated Companies, net 90 (112) (56)
Other Current Assets and Liabilities (3) 14 (40)
Employee Benefit Plan Funding and Related Payments (8) (11) (9)
Other (46) 25 4
Net Cash Provided By (Used In) Operating Activities 1,111 1,479 1,084
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment (404) (607) (996)
Purchase of Emissions Allowances and RECs (111) (98) (146)
Proceeds from Sales of Trust Investments 2,083 1,658 1,423
Purchases of Trust Investments (2,097) (1,685) (1,392)
Proceeds from Sales of Long-Lived Assets 151 70 21
Short-Term Loan to Affiliate (12) (149) -
Other 42 50 39
Net Cash Provided By (Used In) Investing Activities (348) (761) (1,051)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of Long-Term Debt - - 700
Cash Dividend Paid (350) (525) (400)
Redemption of Long-Term Debt (406) - (250)
Short-Term Loan from Affiliate - (193) (88)
Other (1) (1) (5)
Net Cash Provided By (Used In) Financing Activities (757) (719) (43)
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash 6 (1) (10)
Cash, Cash Equivalents and Restricted Cash at Beginning of Period 21 22 32
Cash, Cash Equivalents and Restricted Cash at End of Period $ 27 $ 21 $ 22
Supplemental Disclosure of Cash Flow Information:
Income Taxes Paid (Received) $ 127 $ (41) $ (92)
Interest Paid, Net of Amounts Capitalized $ 119 $ 113 $ 73
Accrued Property, Plant and Equipment Expenditures $ 64 $ 164 $ 167
See disclosures regarding PSEG Power LLC included in the Notes to Consolidated Financial Statements.
PSEG POWER LLC
CONSOLIDATED STATEMENTS OF MEMBER’S EQUITY
Millions
Contributed
Capital Basis
Adjustment Retained
Earnings Accumulated
Other
Comprehensive
Income (Loss) Total
Balance as of December 31, 2017 $ 2,214 $ (986) $ 4,911 $ (172) $ 5,967
Net Income - - 365 - 365
Cumulative Effect Adjustment to Reclassify Unrealized Net Gains on Equity Investments - - 175 (175) -
Other Comprehensive Income (Loss), net of tax (expense) benefit of $(7)
- - - 28 28
Comprehensive Income 393
Cash Dividends Paid - - (400) - (400)
Balance as of December 31, 2018 $ 2,214 $ (986) $ 5,051 $ (319) $ 5,960
Net Income - - 468 - 468
Cumulative Effect Adjustment to Reclassify Stranded Tax Effects Resulting from the Change in the Federal Corporate Income Tax Rate - - 69 (69) -
Other Comprehensive Income (Loss), net of tax (expense) benefit of $(9)
- - - (13) (13)
Comprehensive Income 455
Cash Dividends Paid - - (525) - (525)
Balance as of December 31, 2019 $ 2,214 $ (986) $ 5,063 $ (401) $ 5,890
Net Income - - 594 - 594
Other Comprehensive Income (Loss), net of tax (expense) benefit of $1
- - - (18) (18)
Comprehensive Income 576
Cash Dividends Paid - - (350) - (350)
Non-Cash Contributed Capital Related to Debt Exchange 96 - - - 96
Balance as of December 31, 2020 $ 2,310 $ (986) $ 5,307 $ (419) $ 6,212
See disclosures regarding PSEG Power LLC included in the Notes to Consolidated Financial Statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1. Organization, Basis of Presentation and Summary of Significant Accounting Policies
Public Service Enterprise Group Incorporated (PSEG) is a holding company with a diversified business mix within the energy industry. Its operations are primarily in the Northeastern and Mid-Atlantic United States and in other select markets. PSEG’s principal direct wholly owned subsidiaries are:
•Public Service Electric and Gas Company (PSE&G)-which is a public utility engaged principally in the transmission of electricity and distribution of electricity and natural gas in certain areas of New Jersey. PSE&G is subject to regulation by the New Jersey Board of Public Utilities (BPU) and the Federal Energy Regulatory Commission (FERC). PSE&G also invests in regulated solar generation projects and energy efficiency and related programs in New Jersey, which are regulated by the BPU.
•PSEG Power LLC (PSEG Power)-which is a multi-regional energy supply company that integrates the operations of its merchant nuclear and fossil generating assets with its power marketing businesses and fuel supply functions through competitive energy sales in well-developed energy markets primarily in the Northeast and Mid-Atlantic United States through its principal direct wholly owned subsidiaries. In addition, PSEG Power owns and operates solar generation in various states. PSEG Power’s subsidiaries are subject to regulation by FERC, the Nuclear Regulatory Commission (NRC), the Environmental Protection Agency (EPA) and the states in which they operate.
PSEG’s other direct wholly owned subsidiaries are: PSEG Long Island LLC (PSEG LI), which operates the Long Island Power Authority’s (LIPA) electric transmission and distribution (T&D) system under an Amended and Restated Operations Services Agreement (OSA); PSEG Energy Holdings L.L.C. (Energy Holdings), which earns it revenues from its portfolio of lease investments and holds our investment in offshore wind ventures; and PSEG Services Corporation (Services), which provides certain management, administrative and general services to PSEG and its subsidiaries at cost.
Basis of Presentation
The respective financial statements included herein have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (SEC) applicable to Annual Reports on Form 10-K and in accordance with accounting guidance generally accepted in the United States (GAAP).
Significant Accounting Policies
Principles of Consolidation
Each company consolidates those entities in which it has a controlling interest or is the primary beneficiary. See Note 5. Variable Interest Entity. Entities over which the companies exhibit significant influence, but do not have a controlling interest and/or are not the primary beneficiary, are accounted for under the equity method of accounting. For investments in which significant influence does not exist and the investor is not the primary beneficiary, the cost method of accounting is applied. All significant intercompany accounts and transactions are eliminated in consolidation.
PSE&G and PSEG Power also have undivided interests in certain jointly-owned facilities, with each responsible for paying its respective ownership share of construction costs, fuel purchases and operating expenses. PSE&G and PSEG Power consolidate their portion of any revenues and expenses related to their respective jointly-owned facilities in the appropriate revenue and expense categories.
Accounting for the Effects of Regulation
In accordance with accounting guidance for rate-regulated entities, PSE&G’s financial statements reflect the economic effects of regulation. PSE&G defers the recognition of costs (a Regulatory Asset) or records the recognition of obligations (a Regulatory Liability) if it is probable that, through the rate-making process, there will be a corresponding increase or decrease in future rates. Accordingly, PSE&G has deferred certain costs and recoveries, which are being amortized over various future periods. To the extent that collection of any such costs or payment of liabilities becomes no longer probable as a result of changes in regulation and/or competitive position, the associated Regulatory Asset or Liability is charged or credited to income. Management believes that PSE&G’s T&D businesses continue to meet the accounting requirements for rate-regulated entities. For additional information, see Note 7. Regulatory Assets and Liabilities.
Cash, Cash Equivalents and Restricted Cash
The following provides a reconciliation of cash, cash equivalents and restricted cash reported within the Consolidated Balance Sheets that sum to the total of the same such amounts in the Consolidated Statements of Cash Flows for the years ended
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2019 and 2020. Restricted cash consists primarily of deposits received related to various construction projects at PSE&G.
PSE&G PSEG Power Other (A) Consolidated
Millions
As of December 31, 2019
Cash and Cash Equivalents $ 21 $ 21 $ 105 $ 147
Restricted Cash in Other Current Assets 11 - - 11
Restricted Cash in Other Noncurrent Assets 18 - - 18
Cash, Cash Equivalents and Restricted Cash $ 50 $ 21 $ 105 $ 176
As of December 31, 2020
Cash and Cash Equivalents $ 204 $ 27 $ 312 $ 543
Restricted Cash in Other Current Assets 7 - - 7
Restricted Cash in Other Noncurrent Assets 22 - - 22
Cash, Cash Equivalents and Restricted Cash $ 233 $ 27 $ 312 $ 572
(A)Includes amounts applicable to PSEG (parent company), Energy Holdings and Services.
Derivative Instruments
Each company uses derivative instruments to manage risk pursuant to its business plans and prudent practices.
Within PSEG and its affiliate companies, PSEG Power has the most exposure to commodity price risk. PSEG Power is exposed to commodity price risk primarily relating to changes in the market price of electricity, fossil fuels and other commodities. Fluctuations in market prices result from changes in supply and demand, fuel costs, market conditions, weather, state and federal regulatory policies, environmental policies, transmission availability and other factors. PSEG Power uses a variety of derivative and non-derivative instruments, such as financial options, futures, swaps, fuel purchases and forward purchases and sales of electricity, to manage the exposure to fluctuations in commodity prices and optimize the value of PSEG Power’s expected generation. Changes in the fair market value of the derivative contracts are recorded in earnings.
Determining whether a contract qualifies as a derivative requires that management exercise significant judgment, including assessing the contract’s market liquidity. PSEG has determined that contracts to purchase and sell certain products do not meet the definition of a derivative under the current authoritative guidance since they do not provide for net settlement, or the markets are not sufficiently liquid to conclude that physical forward contracts are readily convertible to cash.
Under current authoritative guidance, all derivatives are recognized on the balance sheet at their fair value, except for derivatives that are designated as normal purchases and normal sales (NPNS). Further, derivatives that qualify for hedge accounting can be designated as fair value or cash flow hedges. For fair value hedges, changes in fair values for both the derivative and the underlying hedged exposure are recognized in earnings each period.
Certain offsetting derivative assets and liabilities are subject to a master netting or similar agreement. In general, the terms of the agreements provide that in the event of an early termination the counterparties have the right to offset amounts owed or owing under that and any other agreement with the same counterparty. Accordingly, these positions are offset on the Consolidated Balance Sheets of PSEG Power and PSEG.
For cash flow hedges, the gain or loss on a derivative instrument designated and qualifying as a cash flow hedge is deferred in Accumulated Other Comprehensive Income (Loss) until earnings are affected by the variability of cash flows of the hedged transaction.
For derivative contracts that do not qualify or are not designated as cash flow or fair value hedges or as NPNS, changes in fair value are recorded in current period earnings. PSEG does not currently elect fair value or cash flow hedge accounting on its commodity derivative positions.
Contracts that qualify for, and are designated, as NPNS are accounted for upon settlement. Contracts which qualify for NPNS are contracts for which physical delivery is probable, they will not be financially settled, and the quantities under contract are expected to be used or sold in the normal course of business over a reasonable period of time.
For additional information regarding derivative financial instruments, see Note 18. Financial Risk Management Activities.
Revenue Recognition
PSE&G’s regulated electric and gas revenues are recorded primarily based on services rendered to customers. PSE&G records unbilled revenues for the estimated amount customers will be billed for services rendered from the time meters were last read to
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
the end of the respective accounting period. The unbilled revenue is estimated each month based on usage per day, the number of unbilled days in the period, estimated seasonal loads based upon the time of year and the variance of actual degree-days and temperature-humidity-index hours of the unbilled period from expected norms.
Regulated revenues from the transmission of electricity are recognized as services are provided based on a FERC-approved annual formula rate mechanism. This mechanism provides for an annual filing of estimated revenue requirement with rates effective January 1 of each year. After completion of the annual period ending December 31, PSE&G files a true-up whereby it compares its actual revenue requirement to the original estimate to determine any over or under collection of revenue. PSE&G records the estimated financial statement impact of the difference between the actual and the filed revenue requirement as a refund or deferral for future recovery when such amounts are probable and can be reasonably estimated in accordance with accounting guidance for rate-regulated entities.
The majority of PSEG Power’s revenues relate to bilateral contracts, which are accounted for on the accrual basis as the energy is delivered. PSEG Power’s revenue also includes changes in the value of energy derivative contracts that are not designated as NPNS. See Note 18. Financial Risk Management Activities for further discussion.
PJM Interconnection, L.L.C. (PJM), the Independent System Operator-New England (ISO-NE) and the New York Independent System Operator (NYISO) facilitate the dispatch of energy and energy-related products. PSEG Power generally reports electricity sales and purchases conducted with those individual ISOs on a net hourly basis in either Revenues or Energy Costs in its Consolidated Statement of Operations, the classification of which depends on the net hourly activity. Capacity revenue and expense are also reported net based on PSEG Power’s monthly net sale or purchase position in the individual ISOs.
PSEG LI is the primary beneficiary of Long Island Electric Utility Servco, LLC (Servco). For transactions in which Servco acts as principal, Servco records revenues and the related pass-through expenditures separately in Operating Revenues and Operations and Maintenance (O&M) Expense, respectively. See Note 5. Variable Interest Entity for further information.
For additional information regarding Revenues, see Note 3. Revenues.
Depreciation and Amortization (D&A)
PSE&G calculates depreciation under the straight-line method based on estimated average remaining lives of the several classes of depreciable property. These estimates are reviewed on a periodic basis and necessary adjustments are made as approved by the BPU or FERC. The average depreciation rate stated as a percentage of original cost of depreciable property was as follows:
2020 2019 2018
Avg Rate Avg Rate Avg Rate
Electric Transmission 2.41 % 2.41 % 2.42 %
Electric Distribution 2.55 % 2.54 % 2.51 %
Gas Distribution 1.84 % 1.85 % 1.61 %
PSEG Power calculates depreciation on generation-related assets under the straight-line method based on the assets’ estimated useful lives. The estimated useful lives are:
•general plant assets-3 years to 20 years
•fossil production assets-30 years to 56 years
•nuclear generation assets-approximately 60 years to 80 years
•solar assets-25 years to 35 years
Allowance for Funds Used During Construction (AFUDC) and Interest Capitalized During Construction (IDC)
AFUDC represents the cost of debt and equity funds used to finance the construction of new utility assets at PSE&G. IDC represents the cost of debt used to finance construction at PSEG Power. The amount of AFUDC or IDC capitalized as Property, Plant and Equipment is included as a reduction of interest charges or other income for the equity portion. The amounts and average rates used to calculate AFUDC or IDC for the years ended December 31, 2020, 2019 and 2018 were as follows:
AFUDC/IDC Capitalized
2020 2019 2018
Millions Avg Rate Millions Avg Rate Millions Avg Rate
PSE&G $ 112 7.86 % $ 81 7.22 % $ 70 7.74 %
PSEG Power $ 10 4.60 % $ 27 4.60 % $ 67 4.60 %
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Income Taxes
PSEG and its subsidiaries file a consolidated federal income tax return and income taxes are allocated to PSEG’s subsidiaries based on the taxable income or loss of each subsidiary on a separate return basis in accordance with a tax-sharing agreement between PSEG and each of its affiliated subsidiaries. Allocations between PSEG and its subsidiaries are recorded through intercompany accounts. Investment tax credits deferred in prior years are being amortized over the useful lives of the related property.
Uncertain income tax positions are accounted for using a benefit recognition model with a two-step approach, a more-likely-than-not recognition criterion and a measurement attribute that measures the position as the largest amount of tax benefit that is greater than 50% likely of being realized upon ultimate settlement. If it is not more-likely-than-not that the benefit will be sustained on its technical merits, no benefit will be recorded. Uncertain tax positions that relate only to timing of when an item is included on a tax return are considered to have met the recognition threshold. See Note 22. Income Taxes for further discussion.
Impairment of Long-Lived Assets and Leveraged Leases
Management evaluates long-lived assets for impairment whenever events or changes in circumstances, such as significant adverse changes in regulation, business climate, counterparty credit worthiness or market conditions, including prolonged periods of adverse commodity and capacity prices or a current expectation that a long-lived asset will be sold or disposed of significantly before the end of its previously estimated useful life, could potentially indicate an asset’s or asset group’s carrying amount may not be recoverable. In such an event, an undiscounted cash flow analysis is performed to determine if an impairment exists. When a long-lived asset’s or asset group’s carrying amount exceeds the associated undiscounted estimated future cash flows, the asset/asset group is considered impaired to the extent that its fair value is less than its carrying amount. An impairment would result in a reduction of the value of the long-lived asset/asset group through a non-cash charge to earnings.
For PSEG Power, cash flows for long-lived assets and asset groups are determined at the lowest level for which identifiable cash flows are largely independent of the cash flows of other assets and liabilities. The cash flows from the generation units are generally evaluated at a regional portfolio level (PJM, NYISO, ISO-NE) along with cash flows generated from the customer supply and risk management activities, inclusive of cash flows from contracts, including those that are accounted for as derivatives and meet the NPNS scope exception. In certain cases, generation assets are evaluated on an individual basis where those assets are individually contracted on a long-term basis with a third party and operations are independent of other generation assets (typically PSEG Power’s solar units and Kalaeloa). See Note 4. Early Plant Retirements/Asset Dispositions for more information on impairment assessments performed on PSEG Power’s long-lived assets.
Energy Holdings’ leveraged leases are comprised of Lease Receivables (net of non-recourse debt), the estimated residual value of leased assets, and unearned and deferred income. Residual values are the estimated values of the leased assets at the end of the respective lease per the original lease terms, net of any subsequent impairments. A review of the residual valuations, which are calculated by discounting the cash flows related to the leased assets after the lease term, is performed at least annually for each asset subject to lease using specific assumptions tailored to each asset. Those valuations are compared to the recorded residual values to determine if an impairment is warranted.
Accounts Receivable-Allowance for Credit Losses
PSE&G’s accounts receivable, including unbilled revenues, are primarily comprised of utility customer receivables for the provision of electric and gas service and appliance services, and are reported in the balance sheet as gross outstanding amounts adjusted for an allowance for credit losses. The allowance for credit losses reflects PSE&G’s best estimate of losses on the account balances. The allowance is based on PSE&G’s projection of accounts receivable aging, historical experience, economic factors and other currently available evidence, including the estimated impact of the ongoing coronavirus pandemic on the outstanding balances as of December 31, 2020. PSE&G’s electric bad debt expense is recovered through the Societal Benefits Clause mechanism and incremental gas bad debt has been deferred for future recovery through the COVID-19 Regulatory Asset. See Note 3. Revenues and Note 7. Regulatory Assets and Liabilities.
Accounts receivable are charged off in the period in which the receivable is deemed uncollectible. Recoveries of accounts receivable are recorded when it is known they will be received.
Materials and Supplies and Fuel
PSE&G’s and PSEG Power’s materials and supplies are carried at average cost and charged to inventory when purchased and expensed or capitalized to Property, Plant and Equipment, as appropriate, when installed or used. Fuel inventory at PSEG Power is valued at the lower of average cost or market and includes stored natural gas, coal, fuel oil and propane used to generate power and to satisfy obligations under PSEG Power’s gas supply contracts with PSE&G. The costs of fuel, including initial transportation costs, are included in inventory when purchased and charged to Energy Costs when used or sold. The cost
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
of nuclear fuel is capitalized within Property, Plant and Equipment and amortized to fuel expense using the units-of-production method.
In 2020, PSEG Power recorded a $2 million lower of cost or market (LOCOM) adjustment to its fuel oil inventory due to the decline in market pricing.
Property, Plant and Equipment
PSE&G’s additions to and replacements of existing property, plant and equipment are capitalized at cost. The cost of maintenance, repair and replacement of minor items of property is charged to expense as incurred. At the time units of depreciable property are retired or otherwise disposed of, the original cost, adjusted for net salvage value, is charged to accumulated depreciation.
PSEG Power capitalizes costs, including those related to its jointly-owned facilities that increase the capacity, improve or extend the life of an existing asset; represent a newly acquired or constructed asset; or represent the replacement of a retired asset. The cost of maintenance, repair and replacement of minor items of property is charged to appropriate expense accounts as incurred. Environmental costs are capitalized if the costs mitigate or prevent future environmental contamination or if the costs improve existing assets’ environmental safety or efficiency. All other environmental expenditures are expensed as incurred. PSEG Power also capitalizes spare parts that meet specific criteria. Capitalized spares are depreciated over the remaining lives of their associated assets.
Leases
Effective January 1, 2019, PSEG and its subsidiaries adopted new accounting guidance which requires lessees to recognize leases with a term greater than 12 months on the balance sheet using a right-of-use asset approach.
PSEG and its subsidiaries, when acting as lessee or lessor, determine if an arrangement is a lease at inception. PSEG assesses contracts to determine if the arrangement conveys (i) the right to control the use of the identified property, (ii) the right to obtain substantially all of the economic benefits from the use of the property, and (iii) the right to direct the use of the property.
PSEG and its subsidiaries are neither the lessee nor the lessor in any material leases that are not classified as operating leases.
Lessee-Operating Lease Right-of-Use Assets represent the right to use an underlying asset for the lease term and Operating Lease Liabilities represent the obligation to make lease payments arising from the lease. Operating Lease Right-of-Use Assets and Operating Lease Liabilities are recognized at the lease commencement date based on the present value of lease payments over the lease term.
The current portion of Operating Lease Liabilities is included in Other Current Liabilities. Operating Lease Right-of-Use Assets and noncurrent Operating Lease Liabilities are included as separate captions in Noncurrent Assets and Noncurrent Liabilities, respectively, on the Consolidated Balance Sheets of PSEG, PSE&G and PSEG Power. PSEG and its subsidiaries do not recognize Operating Lease Right-of-Use Assets and Operating Lease Liabilities for leases where the term is twelve months or less.
PSEG and its subsidiaries recognize the lease payments on a straight-line basis over the term of the leases and variable lease payments in the period in which the obligations for those payments are incurred.
As lessee, most of the operating leases of PSEG and its subsidiaries do not provide an implicit rate; therefore, incremental borrowing rates are used based on the information available at commencement date in determining the present value of lease payments. The implicit rate is used when readily determinable. PSE&G’s incremental borrowing rates are based on secured borrowing rates. PSEG’s and PSEG Power’s incremental borrowing rates are generally unsecured rates. Having calculated simulated secured rates for each of PSEG and PSEG Power, it was determined that the difference between the unsecured borrowing rates and the simulated secured rates had an immaterial effect on their recorded Operating Lease Right-of-Use Assets and Operating Lease Liabilities. Services, PSEG LI and other subsidiaries of PSEG that do not borrow funds or issue debt may enter into leases. Since these companies do not have credit ratings and related incremental borrowing rates, PSEG has determined that it is appropriate for these companies to use the incremental borrowing rate of PSEG, the parent company.
Lease terms may include options to extend or terminate the lease when it is reasonably certain that such options will be exercised.
PSEG and its subsidiaries have lease agreements with lease and non-lease components. For real estate, equipment and vehicle leases, the lease and non-lease components are accounted for as a single lease component.
Lessor-Property subject to operating leases, where PSEG or one of its subsidiaries is the lessor, is included in Property, Plant and Equipment and rental income from these leases is included in Operating Revenues.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PSEG and its subsidiaries, have lease agreements with lease and non-lease components, which are primarily related to domestic energy generation including solar generation facilities. PSEG and subsidiaries account for the lease and non-lease components as a single lease component. See Note 8. Leases for detailed information on leases.
Energy Holdings is the lessor in leveraged leases. Leveraged lease accounting guidance is grandfathered for existing leveraged leases. Energy Holdings’ leveraged leases are accounted for in Operating Revenues and in Noncurrent Long-Term Investments. If modified after January 1, 2019, those leveraged leases will be accounted for as operating or financing leases. See Note 9. Long-Term Investments and Note 10. Financing Receivables.
Trust Investments
These securities comprise the Nuclear Decommissioning Trust (NDT) Fund, a master independent external trust account maintained to provide for the costs of decommissioning upon termination of operations of PSEG Power’s nuclear facilities and amounts that are deposited to fund a Rabbi Trust which was established to meet the obligations related to non-qualified pension plans and deferred compensation plans.
Unrealized gains and losses on equity security investments are recorded in Net Income. The debt securities are classified as available-for-sale with the unrealized gains and losses recorded as a component of Accumulated Other Comprehensive Income (Loss). Realized gains and losses on both equity and available-for-sale debt security investments are recorded in earnings and are included with the unrealized gains and losses on equity securities in Net Gains (Losses) on Trust Investments. Other-than-temporary impairments on NDT and Rabbi Trust debt securities are also included in Net Gains (Losses) on Trust Investments. See Note 11. Trust Investments for further discussion.
Pension and Other Postretirement Benefits (OPEB) Plans
The market-related value of plan assets held for the qualified pension and OPEB plans is equal to the fair value of those assets as of year-end. Fair value is determined using quoted market prices and independent pricing services based upon the security type as reported by the trustee at the measurement date (December 31) as well as investments in unlisted real estate which are valued via third-party appraisals.
PSEG recognizes a long-term receivable primarily related to future funding by LIPA of Servco’s recognized pension and OPEB liabilities. This receivable is presented separately on the Consolidated Balance Sheet of PSEG as a noncurrent asset.
Pursuant to the OSA, Servco records expense for contributions to its pension plan trusts and for OPEB payments made to retirees.
See Note 14. Pension, Other Postretirement Benefits (OPEB) and Savings Plans for further discussion.
Basis Adjustment
PSE&G and PSEG Power have recorded a Basis Adjustment in their respective Consolidated Balance Sheets related to the generation assets that were transferred from PSE&G to PSEG Power in August 2000 at the price specified by the BPU. Because the transfer was between affiliates, the transaction was recorded at the net book value of the assets and liabilities rather than the transfer price. The difference between the total transfer price and the net book value of the generation-related assets and liabilities, $986 million, net of tax, was recorded as a Basis Adjustment on PSE&G’s and PSEG Power’s Consolidated Balance Sheets. The $986 million is an addition to PSE&G’s Common Stockholder’s Equity and a reduction of PSEG Power’s Member’s Equity. These amounts are eliminated on PSEG’s consolidated financial statements.
Use of Estimates
The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Note 2. Recent Accounting Standards
New Standards Adopted in 2020
Measurement of Credit Losses on Financial Instruments-Accounting Standards Update (ASU) 2016-13, updated by ASU 2018-19, 2019-04, 2019-05, 2019-11 and 2020-02
This accounting standard provides a new model for recognizing credit losses on financial assets. The new model requires entities to use an estimate of expected credit losses that will be recognized as an impairment allowance rather than a direct write-down of the amortized cost basis. The estimate of expected credit losses is based on past events, current conditions and supportable forecasts over a reasonable period. For purchased financial assets with credit deterioration, a similar model is used;
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
however, the initial allowance is added to the purchase price rather than reported as an allowance. Credit losses on available-for-sale debt securities are measured in a manner similar to current GAAP; however, this standard requires those credit losses be presented as an allowance, rather than a write-down. This new standard also requires additional disclosures of the allowance for credit losses by financial asset type, including disclosures of credit quality indicators for each class of financial asset disaggregated by year of origination.
The standard was effective for annual and interim periods beginning after December 15, 2019. PSEG adopted this standard on January 1, 2020 on a modified retrospective basis. Upon adoption, PSE&G recorded an increase of $8 million to its allowance for credit losses, offset by a $6 million increase to Regulatory and Other Assets, and a $2 million cumulative effect charge to Retained Earnings. See Note 3. Revenues. There was no impact from adoption of this standard on the financial statements of PSEG Power.
Disclosure Framework-Changes to the Disclosure Requirements for Fair Value Measurement-ASU 2018-13
This accounting standard modifies the disclosure requirements for fair value measurements. Certain current disclosure requirements relating to Level 3 fair value measurements, and transfers between Level 1 and Level 2 fair value measurements have been eliminated. The standard also adds certain other disclosure requirements for Level 3 fair value measurements.
The standard was effective for annual and interim periods beginning after December 15, 2019. PSEG adopted this standard on January 1, 2020. Certain amendments in the standard have been applied prospectively in 2020. All other amendments of the standard were applied retrospectively to all periods presented.
Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract-ASU 2018-15
This accounting standard aligns the capitalization requirements for implementation costs incurred in a hosting arrangement that is a service contract with capitalization requirements for implementation costs incurred to develop or obtain internal-use software, including hosting arrangements that include an internal-use software license. The standard follows the guidance in Accounting Standard Codification 350-Intangibles-Goodwill and Other to determine which implementation costs to capitalize as an asset related to the service contract and which costs to expense. The standard requires the amortization of capitalized costs to be presented in O&M Expense. In addition, the standard also adds presentation requirements for these costs in the statements of cash flows and financial position.
The standard was effective for annual and interim periods beginning after December 15, 2019. PSEG adopted this standard prospectively on January 1, 2020. Adoption of this standard did not have a material impact on the financial statements of PSEG, PSE&G and PSEG.
Targeted Improvements to Related Party Guidance for Variable Interest Entities (VIE)-ASU 2018-17
This accounting standard improves the VIE guidance in the area of decision-making fees. Consistent with how indirect interests held through related parties under common control are considered for determining whether a reporting entity must consolidate a VIE, indirect interests held through related parties in common control arrangements are considered on a proportional basis for determining whether fees paid to decision makers and service providers are variable interests.
This standard is effective for annual and interim periods beginning after December 15, 2019. The standard is required to be applied retrospectively with a cumulative effect adjustment to Retained Earnings at the beginning of the earliest period presented. PSEG adopted this standard on January 1, 2020. Adoption of this standard did not have an impact on the financial statements of PSEG, PSE&G and PSEG Power.
Simplifying the Test for Goodwill Impairment-ASU 2017-04
This accounting standard requires an entity to perform its annual or interim goodwill impairment test by comparing the fair value of a reporting unit with its carrying amount. An entity should recognize an impairment charge for the amount by which the carrying amount exceeds the reporting unit’s fair value; however, the loss recognized should not exceed the total amount of goodwill allocated to that reporting unit. Additionally, an entity should consider income tax effects from any tax deductible goodwill on the carrying amount of the reporting unit when measuring the goodwill impairment loss, if applicable.
This standard requires application on a prospective basis. The new standard was effective for impairment tests for periods beginning January 1, 2020. PSEG early adopted this standard in the fourth quarter of 2019, and recorded an impairment loss of $16 million in O&M Expense.
Codification Improvements to Financial Instruments-ASU 2020-03
This accounting standard provides clarification of guidance for financial instruments and makes narrow scope amendments related to various issues. PSEG adopted this standard in the first quarter of 2020. Adoption of this standard did not have an impact on the financial statements of PSEG, PSE&G and PSEG Power.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Facilitation of the Effects of Reference Rate Reform on Financial Reporting-ASU 2020-04
This accounting standard provides optional expedients and exceptions for applying GAAP to contract modifications and hedging relationships, subject to meeting certain criteria, that reference London Interbank Offered Rate (LIBOR) or another reference rate expected to be discontinued. The standard was effective from its issuance date, March 12, 2020, through December 31, 2022. PSEG adopted this standard effective upon issuance. Adoption of this standard did not have an impact on the financial statements of PSEG, PSE&G and PSEG Power.
Disclosure Framework-Changes to the Disclosure Requirements for Defined Benefit Plans-ASU 2018-14
This accounting standard modifies the disclosure requirements for employers that sponsor defined benefit pension or other postretirement plans, including the elimination of certain current disclosure requirements. Certain other disclosure requirements related to interest crediting rates have been added and certain clarifications were made to other disclosure requirements.
The standard is effective for fiscal years ending after December 15, 2020 and early adoption is permitted. Amendments in this standard will be applied on a retrospective basis to all periods presented. PSEG adopted this standard on December 31, 2020. The amendments in the standard have been applied retrospectively to all periods presented. See Note 14. Pension, Other Postretirement Benefits (OPEB) and Savings Plans.
New Standards Issued But Not Yet Adopted As of December 31, 2020
Simplifying the Accounting for Income Taxes-ASU 2019-12
This accounting standard updates ASC 740 to simplify the accounting for income taxes, including the elimination of several exceptions and making other clarifications to the current guidance. Some of the more pertinent modifications include a change to the tax accounting related to franchise taxes that are partially based on income, an election to allocate the consolidated tax expense to a disregarded entity that is a member of a consolidated tax return filing group when those entities issue separate financial statements, and modifications and clarifications to interim tax reporting.
The standard is effective for fiscal years beginning after December 15, 2020 and early adoption is permitted. Amendments will be applied either on a retrospective, modified retrospective through a cumulative adjustment to Retained Earnings in the year of adoption, or on a prospective basis. PSEG adopted this standard on January 1, 2021. PSEG will be electing to allocate the consolidated tax expense to all eligible entities that are included in a consolidated tax filing. Making this election will be consistent with PSEG’s Tax Sharing Agreements with its affiliated subsidiaries, as stated in Note 1. Organization, Basis of Presentation and Summary of Significant Accounting Policies. Adoption of this standard did not have an impact on the financial statements of PSEG, PSE&G, and PSEG Power.
Clarifying the Interactions between Investments-Equity Securities, Investments-Equity Method and Joint Ventures, and Derivatives and Hedging-ASU 2020-01
This accounting standard clarifies that an entity should consider transaction prices for purposes of measuring the fair value of certain equity securities immediately before applying or upon discontinuing the equity method. This accounting standard also clarifies that when accounting for contracts entered into to purchase equity securities, an entity should not consider whether, upon the settlement of the forward contract or exercise of the purchased option, the underlying securities would be accounted for under the equity method or the fair value option.
The standard is effective for fiscal years beginning after December 15, 2020. Amendments in this standard will be applied prospectively. PSEG adopted this standard on January 1, 2021. Adoption of this standard did not have an impact on the financial statements of PSEG, PSE&G and PSEG Power.
Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity-ASU 2020-06
This accounting standard simplifies the accounting for convertible debt and convertible preferred stock by removing the requirements to separately present certain conversion features in equity. In addition, the ASU eliminates certain criteria that must be satisfied in order to classify a contract as equity, which is expected to decrease the number of freestanding instruments and embedded derivatives accounted for as assets or liabilities. The ASU also revises the guidance on calculating earnings per share, requiring use of the if-converted method for all convertible instruments and rescinding the ability to rebut the presumption of share settlement for instruments that may be settled in cash or other assets.
The standard is effective for fiscal years beginning after December 15, 2020. Amendments in this standard will be applied on either a retrospective basis for all periods presented or a modified retrospective basis through a cumulative effect adjustment to Retained Earnings as of the beginning of the fiscal year of adoption. Early adoption is permitted. PSEG adopted this standard on January 1, 2021. Adoption of this standard did not have an impact on the financial statements of PSEG, PSE&G and PSEG Power.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Codification Improvements to Callable Debt Securities-ASU 2020-08
This accounting standard clarifies that an entity should reevaluate for each reporting period whether a purchased callable debt security that has multiple call dates is within the scope of certain guidance on nonrefundable fees and other costs related to receivables.
The standard is effective for fiscal years beginning after December 15, 2020 and early adoption is not permitted. Amendments in this standard will be applied prospectively. PSEG adopted this standard on January 1, 2021. Adoption of this standard did not have an impact on the financial statements of PSEG, PSE&G and PSEG Power.
Amendments to SEC Guidance in the Codification-ASU 2020-09
This accounting standard aligns the SEC guidance in the codification with the SEC rules issued in March 2020 relating to changes in the disclosure requirements for certain debt securities. Certain glossary terms were superseded and amendments were made to debt and other topics as a result of this update.
The standard is effective on January 4, 2021 and early adoption is permitted. PSEG adopted the new SEC rules earlier in 2020 and has eliminated the footnote relating to the guarantors of debt, and now presents summarized Guarantor Financial Information in Item 7. Liquidity and Capital Resources.
Codification Improvements-ASU 2020-10
This accounting standard conforms, clarifies, simplifies, and provides technical corrections to various codification topics.
The standard is effective for fiscal years beginning after December 15, 2020 and early adoption is permitted. PSEG adopted this standard on January 1, 2021. Adoption of this standard did not have an impact on the financial statements of PSEG, PSE&G and PSEG Power.
Reference Rate Reform Scope Refinement-ASU 2021-01
This accounting standard clarifies certain guidance related to derivative instruments affected by the market-wide change in the interest rates even if those derivatives do not reference the LIBOR or another rate that is expected to be discontinued as a result of reference rate reform. The accounting standard also clarifies other aspects of the relief provided in the reference rate reform GAAP guidance.
The standard is effective upon issuance and allows for retrospective or prospective application with certain conditions. PSEG adopted this standard in January 2021. Adoption of this standard did not have an impact on the financial statements of PSEG, PSE&G and PSEG Power.
Note 3. Revenues
Nature of Goods and Services
The following is a description of principal activities by reportable segment from which PSEG, PSE&G and PSEG Power generate their revenues.
PSE&G
Revenues from Contracts with Customers
Electric and Gas Distribution and Transmission Revenues-PSE&G sells gas and electricity to customers under default commodity supply tariffs. PSE&G’s regulated electric and gas default commodity supply and distribution services are separate tariffs which are satisfied as the product(s) and/or service(s) are delivered to the customer. The electric and gas commodity and delivery tariffs are recurring contracts in effect until modified through the regulatory approval process as appropriate. Revenue is recognized over time as the service is rendered to the customer. Included in PSE&G’s regulated revenues are unbilled electric and gas revenues which represent the estimated amount customers will be billed for services rendered from the most recent meter reading to the end of the respective accounting period.
PSE&G’s transmission revenues are earned under a separate tariff using a FERC-approved annual formula rate mechanism. The performance obligation of transmission service is satisfied and revenue is recognized as it is provided to the customer. The formula rate mechanism provides for an annual filing of an estimated revenue requirement with rates effective January 1 of each year and a true-up to that estimate based on actual revenue requirements. The true-up mechanism is an alternative revenue which is outside the scope of revenue from contracts with customers.
Other Revenues from Contracts with Customers
Other revenues from contracts with customers, which are not a material source of PSE&G revenues, are generated primarily from appliance repair services and solar generation projects. The performance obligations under these contracts are satisfied and
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
revenue is recognized as control of products is delivered or services are rendered.
Payment for services rendered and products transferred are typically due on average within 30 days of delivery.
Revenues Unrelated to Contracts with Customers
Other PSE&G revenues unrelated to contracts with customers are derived from alternative revenue mechanisms recorded pursuant to regulatory accounting guidance. These revenues, which include weather normalization, green energy program true-ups and transmission formula rate true-ups, are not a material source of PSE&G revenues.
PSEG Power
Revenues from Contracts with Customers
Electricity and Related Products-Wholesale and retail load contracts are executed in the different Independent System Operator (ISO) regions for the bundled supply of energy, capacity, renewable energy credits (RECs) and ancillary services representing PSEG Power’s performance obligations. Revenue for these contracts is recognized over time as the bundled service is provided to the customer. Transaction terms generally run from several months to three years. PSEG Power also sells to the ISOs energy and ancillary services which are separately transacted in the day-ahead or real-time energy markets. The energy and ancillary services performance obligations are typically satisfied over time as delivered and revenue is recognized accordingly. PSEG Power generally reports electricity sales and purchases conducted with those individual ISOs net on an hourly basis in either Operating Revenues or Energy Costs in its Consolidated Statements of Operations. The classification depends on the net hourly activity.
PSEG Power enters into capacity sales and capacity purchases through the ISOs. The transactions are reported on a net basis dependent on PSEG Power’s monthly net sale or purchase position through the individual ISOs. The performance obligations with the ISOs are satisfied over time upon delivery of the capacity and revenue is recognized accordingly. In addition to capacity sold through the ISOs, PSEG Power sells capacity through bilateral contracts and the related revenue is reported on a gross basis and recognized over time upon delivery of the capacity.
In April 2019, PSEG Power’s Salem 1, Salem 2 and Hope Creek nuclear plants were awarded Zero Emission Certificates (ZECs) by the BPU. These nuclear plants are expected to receive ZEC revenue for approximately three years, through May 2022, from the electric distribution companies (EDCs) in New Jersey. PSEG Power recognizes revenue when the units generate electricity, which is when the performance obligation is satisfied. These revenues are included in PJM Sales in the following tables. See Note 4. Early Plant Retirements/Asset Dispositions for additional information.
Gas Contracts-PSEG Power sells wholesale natural gas, primarily through an index based full-requirements Basic Gas Supply Service (BGSS) contract with PSE&G to meet the gas supply requirements of PSE&G’s customers. The BGSS contract remains in effect unless terminated by either party with a two-year notice. The performance obligation is primarily delivery of gas which is satisfied over time. Revenue is recognized as gas is delivered. Based upon the availability of natural gas, storage and pipeline capacity beyond PSE&G’s daily needs, PSEG Power also sells gas and pipeline capacity to other counterparties under bilateral contracts. The performance obligation under these contracts is satisfied over time upon delivery of the gas or capacity, and revenue is recognized accordingly.
Other Revenues from Contracts with Customers
PSEG Power enters into bilateral contracts to sell solar power and solar RECs from its solar facilities. Contract terms range from 15 to 30 years. The performance obligations are generally solar power and RECs which are transferred to customers upon generation. Revenue is recognized upon generation of the solar power.
PSEG Power has entered into long-term contracts with LIPA for energy management and fuel procurement services. Revenue is recognized over time as services are rendered.
Revenues Unrelated to Contracts with Customers
PSEG Power’s revenues unrelated to contracts with customers include electric, gas and certain energy-related transactions accounted for in accordance with Derivatives and Hedging accounting guidance. See Note 18. Financial Risk Management Activities for further discussion. PSEG Power is also a party to solar contracts that qualify as leases and are accounted for in accordance with lease accounting guidance.
Other
Revenues from Contracts with Customers
PSEG LI has a contract with LIPA which generates revenues. PSEG LI’s subsidiary, Servco records costs which are recovered from LIPA and records the recovery of those costs as revenues when Servco is a principal in the transaction.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Revenues Unrelated to Contracts with Customers
Energy Holdings generates lease revenues which are recorded pursuant to lease accounting guidance.
Disaggregation of Revenues
PSE&G PSEG Power Other Eliminations Consolidated
Millions
Year Ended December 31, 2020
Revenues from Contracts with Customers
Electric Distribution $ 3,130 $ - $ - $ - $ 3,130
Gas Distribution 1,646 - - (12) 1,634
Transmission 1,485 - - - 1,485
Electricity and Related Product Sales
PJM
Third-Party Sales
- 1,551 - - 1,551
Sales to Affiliates
- 447 - (447) -
NY-ISO
- 124 - - 124
ISO-NE
- 126 - - 126
Gas Sales
Third-Party Sales
- 83 - - 83
Sales to Affiliates
- 771 - (771) -
Other Revenues from Contracts with Customers (A) 338 45 587 (4) 966
Total Revenues from Contracts with Customers 6,599 3,147 587 (1,234) 9,099
Revenues Unrelated to Contracts with Customers (B) 9 487 8 - 504
Total Operating Revenues $ 6,608 $ 3,634 $ 595 $ (1,234) $ 9,603
PSE&G PSEG Power Other Eliminations Consolidated
Millions
Year Ended December 31, 2019
Revenues from Contracts with Customers
Electric Distribution $ 3,224 $ - $ - $ - $ 3,224
Gas Distribution 1,870 - - (15) 1,855
Transmission 1,181 - - - 1,181
Electricity and Related Product Sales
PJM
Third-Party Sales
- 1,785 - - 1,785
Sales to Affiliates - 536 - (536) -
NY-ISO
- 143 - - 143
ISO-NE
- 137 - - 137
Gas Sales
Third-Party Sales
- 92 - - 92
Sales to Affiliates
- 927 - (927) -
Other Revenues from Contracts with Customers (A) 284 46 566 (5) 891
Total Revenues from Contracts with Customers 6,559 3,666 566 (1,483) 9,308
Revenues Unrelated to Contracts with Customers (B) 66 719 (17) - 768
Total Operating Revenues $ 6,625 $ 4,385 $ 549 $ (1,483) $ 10,076
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PSE&G PSEG Power Other Eliminations Consolidated
Millions
Year Ended December 31, 2018
Revenues from Contracts with Customers
Electric Distribution $ 3,131 $ - $ - $ - $ 3,131
Gas Distribution 1,756 - - (18) 1,738
Transmission 1,236 - - - 1,236
Electricity and Related Product Sales
PJM
Third-Party Sales
- 1,933 - - 1,933
Sales to Affiliates - 609 - (609) -
NY-ISO
- 209 - - 209
ISO-NE
- 92 - - 92
Gas Sales
Third-Party Sales
- 151 - - 151
Sales to Affiliates
- 861 - (861) -
Other Revenues from Contracts with Customers (A) 275 44 532 (4) 847
Total Revenues from Contracts with Customers 6,398 3,899 532 (1,492) 9,337
Revenues Unrelated to Contracts with Customers (B) 73 247 39 - 359
Total Operating Revenues $ 6,471 $ 4,146 $ 571 $ (1,492) $ 9,696
(A)Includes primarily revenues from appliance repair services at PSE&G, solar power projects and energy management and fuel service contracts with LIPA at PSEG Power, and PSEG LI’s OSA with LIPA in Other.
(B)Includes primarily alternative revenues at PSE&G, derivative contracts and lease contracts at PSEG Power, and lease contracts in Other. For the years ended December 31, 2020, 2019 and 2018, Other includes losses of $26 million, $58 million and $8 million, respectively, related to Energy Holdings’ investments in leases. For additional information, see Note 9. Long-Term Investments.
Contract Balances
PSE&G
PSE&G did not have any material contract balances (rights to consideration for services already provided or obligations to provide services in the future for consideration already received) as of December 31, 2020 and 2019. Substantially all of PSE&G’s accounts receivable and unbilled revenues result from contracts with customers that are priced at tariff rates. Allowances represented approximately 14% and 6% of accounts receivable (including unbilled revenues in 2020) as of December 31, 2020 and 2019, respectively. As of December 31, 2019, there was no allowance for unbilled revenues. Effective January 1, 2020, PSE&G adopted ASU 2016-13 and recorded an allowance for unbilled revenues. See Note 2. Recent Accounting Standards.
The following provides a reconciliation of PSE&G’s allowance for credit losses for the years ended December 31, 2020 and 2019. The allowance is based on PSE&G’s projection of accounts receivable aging, historical experience, economic factors and other currently available evidence, including the estimated impact of the ongoing coronavirus pandemic on the outstanding balances as of December 31, 2020. PSE&G’s electric bad debt expense is recoverable through its Societal Benefits Clause mechanism. As of December 31, 2020, PSE&G deferred incremental gas bad debt expense for future regulatory recovery due to the impact of the ongoing pandemic. See Note 7. Regulatory Assets and Liabilities for additional information.
Years Ended December 31,
2020 2019
Millions
Balance at Beginning of Year $ 68 (A) $ 63
Utility Customer and Other Accounts
Provision 175 87
Write-offs, net of Recoveries of $5 million and $8 million
(37) (90)
Balance at End of Year $ 206 $ 60
(A)Includes an $8 million pre-tax increase upon adoption of ASU 2016-13.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PSEG Power
PSEG Power generally collects consideration upon satisfaction of performance obligations, and therefore, PSEG Power had no material contract balances as of December 31, 2020 and 2019.
PSEG Power’s accounts receivable include amounts resulting from contracts with customers and other contracts which are out of scope of accounting guidance for revenues from contracts with customers. The majority of these accounts receivable are subject to master netting agreements. As a result, accounts receivable resulting from contracts with customers and receivables unrelated to contracts with customers are netted within Accounts Receivable and Accounts Payable on the Consolidated Balance Sheets.
PSEG Power’s accounts receivable consist mainly of revenues from wholesale load contracts and capacity sales which are executed in the different ISO regions. PSEG Power also sells energy and ancillary services directly to ISOs and other counterparties. In the wholesale energy markets in which PSEG Power operates, payment for services rendered and products transferred are typically due within 30 days of delivery. As such, there is little credit risk associated with these receivables. PSEG Power did not record an allowance for credit losses for these receivables as of December 31, 2020. PSEG Power monitors the status of its counterparties on an ongoing basis to assess whether there are any anticipated credit losses.
Other
PSEG LI does not have any material contract balances as of December 31, 2020 and 2019.
Remaining Performance Obligations under Fixed Consideration Contracts
PSEG Power and PSE&G primarily record revenues as allowed by the guidance, which states that if an entity has a right to consideration from a customer in an amount that corresponds directly with the value to the customer of the entity’s performance completed to date, the entity may recognize revenue in the amount to which the entity has a right to invoice. PSEG has future performance obligations under contracts with fixed consideration as follows:
PSEG Power
As previously stated, capacity transactions with ISOs are reported on a net basis dependent on PSEG Power’s monthly net sale or purchase position through the individual ISOs.
Capacity Revenues from the PJM Annual Base Residual and Incremental Auctions-The Base Residual Auction is generally conducted annually three years in advance of the operating period. The 2022/2023 auction has yet to be held and is not expected until mid-2021. PSEG Power expects to realize the following average capacity prices resulting from the base and incremental auctions, including unit specific bilateral contracts for previously cleared capacity obligations.
Delivery Year $ per Megawatt (MW)-Day MW Cleared
June 2020 to May 2021 $167 7,600
June 2021 to May 2022 $180 7,000
Capacity Payments from the ISO-NE Forward Capacity Market (FCM)-The FCM Auction is conducted annually three years in advance of the operating period. The table below includes PSEG Power’s cleared capacity in the FCM Auction for the Bridgeport Harbor Station 5 (BH5), which cleared the 2019/2020 auction at $231/MW-day for seven years, and the planned retirement of Bridgeport Harbor Station 3 (BH3) in May 2021. PSEG Power expects to realize the following average capacity prices for capacity obligations to be satisfied resulting from the FCM Auctions which have been completed through May 2024 and the seven-year rate lock for BH5 through May 2026:
Delivery Year $ per MW-Day (A) MW Cleared
June 2020 to May 2021 $195 1,330
June 2021 to May 2022 $192 950
June 2022 to May 2023 $179 950
June 2023 to May 2024 $152 930
June 2024 to May 2025 $231 480
June 2025 to May 2026 $231 480
(A)Capacity cleared prices for BH5 through 2026 will be escalated based upon the Handy-Whitman Index. These adjustments are not included above.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Bilateral capacity contracts-Capacity obligations pursuant to contract terms through 2029 are anticipated to result in revenues totaling $146 million.
Other
The LIPA OSA is a 12-year services contract ending in 2025 with annual fixed and incentive components. The fixed fee for the provision of services thereunder in 2021 is $68 million and is updated each year based on the change in the Consumer Price Index (CPI).
Note 4. Early Plant Retirements/Asset Dispositions
Nuclear
In April 2019, PSEG Power’s Salem 1, Salem 2 and Hope Creek nuclear plants were awarded ZECs by the BPU. Pursuant to a process established by the BPU, ZECs are purchased from selected nuclear plants and recovered through a non-bypassable distribution charge in the amount of $0.004 per kilowatt-hour (KWh) used (which is equivalent to approximately $10 per megawatt hour (MWh) generated in payments to selected nuclear plants (ZEC payment)). These nuclear plants are expected to receive ZEC revenue for approximately three years, through May 2022, and will be obligated to maintain operations during that period, subject to exceptions specified in the ZEC legislation. PSEG Power has and will continue to recognize revenue monthly as the nuclear plants generate electricity and satisfy their performance obligations. The ZEC payment may be adjusted by the BPU (a) at any time to offset environmental or fuel diversity payments that a selected nuclear plant may receive from another source or (b) at certain times specified in the ZEC legislation if the BPU determines that the purposes of the ZEC legislation can be achieved through a reduced charge that will nonetheless be sufficient to achieve the state’s air quality and other environmental objectives by preventing the retirement of nuclear plants. For instance, the New Jersey Rate Counsel, in written comments filed with the BPU, has advocated for the BPU to offset market benefits resulting from New Jersey’s rejoining the Regional Greenhouse Gas Initiative from the ZEC payment. PSEG intends to vigorously defend against these arguments. Due to its preliminary nature, PSEG cannot predict the outcome of this matter.
The BPU’s decision awarding ZECs has been appealed by the New Jersey Rate Counsel. PSEG cannot predict the outcome of this matter.
In October 2020, PSEG Power filed with the BPU its ZEC applications for Salem 1, Salem 2 and Hope Creek for the three-year eligibility period starting in June 2022. No other plants applied for ZECs for this eligibility period. PSEG Power is not aware of any changes from its ZEC application for the first eligibility period that would materially affect its ability to establish eligibility to be awarded ZECs during the second eligibility period. A final BPU decision is expected in April 2021. 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; (ii) the amount of ZEC payments that may be awarded or other terms and conditions of the second ZEC eligibility period proposed by the BPU in its final decision differ from those of the current ZEC period; or (iii) any of the Salem 1, Salem 2 and Hope Creek plants is not awarded ZEC payments by the BPU and does not otherwise experience a material financial change, PSEG Power will take all necessary steps to cease to operate all of these plants. Alternatively, if all of the Salem 1, Salem 2 and Hope Creek plants are selected to continue to receive ZEC payments but the financial condition of the plants is materially adversely impacted by changes in commodity prices, FERC’s changes to the capacity market construct (absent sufficient capacity revenues provided under a program approved by the BPU in accordance with a FERC-authorized capacity mechanism), or, in the case of the Salem nuclear plants, decisions by the EPA and state environmental regulators regarding the implementation of Section 316(b) of the Clean Water Act (CWA) and related state regulations, or other factors, PSEG Power will take all necessary steps to cease to operate all of these plants and will incur associated costs and accounting charges. These may include, among other things, one-time impairment charges or accelerated D&A Expense on the remaining carrying value of the plants, potential penalties associated with the early termination of capacity obligations and fuel contracts, accelerated asset retirement costs, severance costs, environmental remediation costs and, in certain circumstances potential additional funding of the NDT Fund, which would be material to both PSEG and PSEG Power.
Non-Nuclear
In July 2020, PSEG announced that it is exploring strategic alternatives for PSEG Power’s non-nuclear generating fleet, which includes more than 6,750 MW of fossil generation located in New Jersey, Connecticut, New York and Maryland as well as the 467 MW Solar Source portfolio located in various states. PSEG intends to retain ownership of PSEG Power’s existing nuclear fleet. The marketing of a potential transaction in one or a series of steps launched in the fourth quarter of 2020, and any potential transaction is expected to be completed sometime in 2021. As a result of the strategic review of PSEG Power’s non-nuclear generating assets, and the launch in the fourth quarter of 2020 of an associated marketing process for their potential disposition, PSEG Power performed an impairment assessment of its PJM, NYISO and ISO-NE asset groupings, as well as for
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
its solar assets, as of September 30, 2020 and December 31, 2020. The assessments included probability weightings assigned to undiscounted cash flow scenarios of retaining the assets through the end of their estimated useful lives and a successful disposition of the non-nuclear assets in 2021. Estimates of cash flows associated with a sale scenario were based on management’s expectations of the fair value of such assets. The probability weighted aggregation of undiscounted cash flows for each of the asset groupings expected to result from the use and potential disposition of the asset groups exceeded their carrying value at the above mentioned September 30, 2020 and December 31, 2020 assessment dates. As such, it demonstrated that no impairment exists for any of the asset groupings and they continue to remain classified as held-for-use as of December 31, 2020. However, certain assumptions are subject to change as the potential sales and marketing process progresses. The carrying value of the fossil generation and of the solar assets (net of eligible investment tax credits (ITC)) was $4.5 billion and $560 million, respectively, as of December 31, 2020.
There is no assurance that the strategic review will result in a sale or other disposition of all or any portion of these assets on terms that are favorable to us, or at all. Any transaction would be subject to market conditions and customary closing conditions, including the receipt of all required regulatory approvals. Management expects that a change in the probability of a successful disposition based upon further progression in the marketing process, but prior to meeting all necessary held-for-sale classification criteria, would result in an impairment of the ISO-NE asset grouping, which would be material. Furthermore, a change to a held-for-sale classification from a held-for-use classification would result in an impairment of the PJM, NYISO and ISO-NE asset groupings, which would be material.
In September 2020, PSEG Power completed the sale of its ownership interest in the Yards Creek generation facility. PSEG Power recorded a pre-tax gain on disposition of approximately $122 million in the third quarter of 2020 as the sale price was greater than book value.
In September 2019, PSEG Power completed the sale of its ownership interests in the Keystone and Conemaugh generation plants and related assets and liabilities. PSEG Power recorded a pre-tax loss on disposition of approximately $400 million in the second quarter of 2019 as the sale price was less than book value.
In December 2018, PSEG Power completed the sale of the sites of the retired Hudson and Mercer units. PSEG Power transferred all land rights and structures on the sites to a third-party purchaser, along with the assumption of the environmental liabilities for the sites. As a result of the sale and transfer of liabilities, PSEG Power recorded a pre-tax gain in 2018 of $54 million.
Note 5. Variable Interest Entity (VIE)
VIE for which PSEG LI is the Primary Beneficiary
PSEG LI consolidates Servco, a marginally capitalized VIE, which was created for the purpose of operating LIPA’s T&D system in Long Island, New York as well as providing administrative support functions to LIPA. PSEG LI is the primary beneficiary of Servco because it directs the operations of Servco, the activity that most significantly impacts Servco’s economic performance and it has the obligation to absorb losses of Servco that could potentially be significant to Servco. Such losses would be immaterial to PSEG.
Pursuant to the OSA, Servco’s operating costs are paid entirely by LIPA, and therefore, PSEG LI’s risk is limited related to the activities of Servco. PSEG LI has no current obligation to provide direct financial support to Servco. In addition to payment of Servco’s operating costs as provided for in the OSA, PSEG LI receives an annual contract management fee. PSEG LI’s annual contractual management fee, in certain situations, could be partially offset by Servco’s annual storm costs not approved by the Federal Emergency Management Agency, limited contingent liabilities and penalties for failing to meet certain performance metrics.
For transactions in which Servco acts as principal and controls the services provided to LIPA, such as transactions with its employees for labor and labor-related activities, including pension and OPEB-related transactions, Servco records revenues and the related pass-through expenditures separately in Operating Revenues and O&M Expense, respectively. In 2020, 2019 and 2018, Servco recorded $520 million, $490 million and $458 million, respectively, of O&M costs. For transactions in which Servco acts as an agent for LIPA, it records revenues and the related expenses on a net basis, resulting in no impact on PSEG’s Consolidated Statement of Operations.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 6. Property, Plant and Equipment and Jointly-Owned Facilities
Information related to Property, Plant and Equipment as of December 31, 2020 and 2019 is detailed below:
PSE&G PSEG Power Other PSEG
Consolidated
Millions
Transmission and Distribution:
Electric Transmission $ 14,075 $ - $ - $ 14,075
Electric Distribution 9,622 - - 9,622
Gas Distribution and Transmission 9,081 - - 9,081
Construction Work in Progress 1,783 - - 1,783
Other 659 - - 659
Total Transmission and Distribution 35,220 - - 35,220
Generation:
Fossil Production - 6,581 - 6,581
Nuclear Production - 3,296 - 3,296
Nuclear Fuel in Service - 748 - 748
Other Production-Solar 658 911 - 1,569
Construction Work in Progress - 248 - 248
Total Generation 658 11,784 - 12,442
Other 422 88 397 907
Total $ 36,300 $ 11,872 $ 397 $ 48,569
PSE&G PSEG Power Other PSEG
Consolidated
Millions
Transmission and Distribution:
Electric Transmission $ 12,908 $ - $ - $ 12,908
Electric Distribution 9,255 - - 9,255
Gas Distribution and Transmission 8,430 - - 8,430
Construction Work in Progress 1,607 - - 1,607
Other 639 - - 639
Total Transmission and Distribution 32,839 - - 32,839
Generation:
Fossil Production - 6,570 - 6,570
Nuclear Production - 3,087 - 3,087
Nuclear Fuel in Service - 761 - 761
Other Production-Solar 663 911 - 1,574
Construction Work in Progress - 277 - 277
Total Generation 663 11,606 - 12,269
Other 398 93 345 836
Total $ 33,900 $ 11,699 $ 345 $ 45,944
PSE&G and PSEG Power have ownership interests in and are responsible for providing their respective shares of the necessary financing for the following jointly-owned facilities to which they are a party. All amounts reflect PSE&G’s or PSEG Power’s share of the jointly-owned projects and the corresponding direct expenses are included in the Consolidated Statements of Operations as Operating Expenses.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
As of December 31,
2020 2019
Ownership Accumulated Accumulated
Interest Plant Depreciation Plant Depreciation
Millions
PSE&G:
Transmission Facilities Various $ 161 $ 63 $ 161 $ 60
PSEG Power:
Nuclear Generating:
Peach Bottom 50 % $ 1,405 $ 455 $ 1,340 $ 435
Salem 57 % $ 1,321 $ 387 $ 1,256 $ 384
Nuclear Support Facilities Various $ 226 $ 97 $ 247 $ 107
Pumped Storage Facilities:
Yards Creek (A) 50 % $ - $ - $ 55 $ 27
Merrill Creek Reservoir 14 % $ 1 $ - $ 1 $ -
(A)In September 2020, PSEG Power completed the sale of its ownership interest in this generation facility. See Note 4. Early Plant Retirements/Asset Dispositions for additional information.
PSEG Power holds undivided ownership interests in the jointly-owned facilities above. PSEG Power is entitled to shares of the generating capability and output of each unit equal to its respective ownership interests. PSEG Power also pays its ownership share of additional construction costs, fuel inventory purchases and operating expenses. PSEG Power’s share of expenses for the jointly-owned facilities is included in the appropriate expense category. Each owner is responsible for any financing with respect to its pro rata share of capital expenditures.
PSEG Power co-owns Salem and Peach Bottom with Exelon Generation. PSEG Power is the operator of Salem and Exelon Generation is the operator of Peach Bottom. A committee appointed by the co-owners provides oversight. Proposed O&M budgets and requests for major capital expenditures are reviewed and approved as part of the normal PSEG Power governance process.
PSEG Power is a minority owner in the Merrill Creek Reservoir and Environmental Preserve in Warren County, New Jersey. Merrill Creek Owners Group is the owner-operator of this facility. The operator submits separate capital and O&M budgets, subject to PSEG Power’s approval as part of the normal PSEG Power governance process.
Note 7. Regulatory Assets and Liabilities
PSE&G prepares its financial statements in accordance with GAAP for regulated utilities as described in Note 1. Organization, Basis of Presentation and Summary of Significant Accounting Policies. PSE&G has deferred certain costs based on rate orders issued by the BPU or FERC or based on PSE&G’s experience with prior rate proceedings. Most of PSE&G’s Regulatory Assets and Liabilities as of December 31, 2020 are supported by written orders, either explicitly or implicitly through the BPU’s treatment of various cost items. These costs will be recovered and amortized over various future periods.
Regulatory Assets and other investments and costs incurred under our various infrastructure filings and clause mechanisms are subject to prudence reviews and can be disallowed in the future by regulatory authorities. To the extent that collection of any infrastructure or clause mechanism revenue, Regulatory Assets or payments of Regulatory Liabilities is no longer probable, the amounts would be charged or credited to income.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PSE&G had the following Regulatory Assets and Liabilities:
As of December 31,
2020 2019
Millions
Regulatory Assets
Current
New Jersey Clean Energy Program $ 143 $ 143
Societal Benefits Charge (SBC) 82 30
Electric Energy Costs-Basic Generation Service (BGS) 60 57
2018 Distribution Base Rate Case Regulatory Assets (BRC) 56 56
Formula Rate True-up 23 52
Other 5 13
Total Current Regulatory Assets 369 351
Noncurrent
Pension and OPEB Costs $ 1,489 $ 1,284
Deferred Income Tax Regulatory Assets 1,014 966
Manufactured Gas Plant (MGP) Remediation Costs 320 357
Electric Transmission and Gas Cost of Removal 189 216
Asset Retirement Obligation 184 172
Green Program Recovery Charges (GPRC) 139 118
Remediation Adjustment Charge (RAC) (Other SBC) 134 158
BRC 103 159
Deferred Storm Costs 99 12
COVID-19 Deferral 51 -
Unamortized Loss on Reacquired Debt and Debt Expense 36 42
Gas Costs-BGSS 26 27
Other 88 166
Total Noncurrent Regulatory Assets 3,872 3,677
Total Regulatory Assets $ 4,241 $ 4,028
As of December 31,
2020 2019
Millions
Regulatory Liabilities
Current
Deferred Income Tax Regulatory Liabilities $ 223 $ 193
Gas Costs-BGSS 20 -
ZEC Liability 17 10
Tax Adjustment Credit (TAC) 5 12
Weather Normalization Charge (WNC) 2 15
Other 27 4
Total Current Regulatory Liabilities 294 234
Noncurrent
Deferred Income Tax Regulatory Liabilities $ 2,670 $ 2,955
Electric Distribution Cost of Removal 37 47
Total Noncurrent Regulatory Liabilities 2,707 3,002
Total Regulatory Liabilities $ 3,001 $ 3,236
All Regulatory Assets and Liabilities are excluded from PSE&G’s rate base unless otherwise noted. The Regulatory Assets and Liabilities in the table above are defined as follows:
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
•Asset Retirement Obligation: These costs represent the differences between rate-regulated cost of removal accounting and asset retirement accounting under GAAP. These costs will be recovered in future rates as assets are retired.
•BRC: Represents deferred costs, primarily comprised of storm costs incurred in the cleanup of major storms from 2010 through 2018, which are being amortized over five years pursuant to the 2018 Distribution Base Rate Case Settlement.
•COVID-19 Deferral: These amounts represent incremental costs related to COVID-19 as authorized for deferral in an order issued by the BPU to all New Jersey regulated utilities in July 2020. The BPU authorized such utilities to create a COVID-19-related Regulatory Asset by deferring on their books and records the prudently incurred incremental costs related to COVID-19 during the Regulatory Asset period, beginning on March 9, 2020 through September 30, 2021, or 60 days after the New Jersey governor determines that the Public Health Emergency is no longer in effect, or in the absence of such a determination, 60 days from the time the Public Health Emergency automatically terminates by law, whichever is later. Deferred costs are to be offset by any federal or state assistance that the utility may receive as a direct result of the COVID-19 pandemic. Utilities must file quarterly reports of the costs incurred and offsets. Each participating utility must file a petition documenting its prudently incurred incremental COVID-19 costs by December 31, 2021, or within 60 days of the close of the Regulatory Asset period as described above, whichever is later. Any potential rate recovery, including any prudency determinations and the appropriate period of recovery, will be addressed through that filing, or in the alternative, the utility may request that the BPU defer consideration of rate recovery for a future base rate case.
•Deferred Income Tax Regulatory Assets: These amounts relate to deferred income taxes arising from utility operations that have not been included in customer rates relating to depreciation, ITCs and other flow-through items, including the flowback to customers of accumulated deferred income taxes related to tax repair deductions. As part of its base rate case settlement with the BPU and the establishment of the TAC mechanism in 2018, PSE&G agreed to a ten-year flowback to customers of its accumulated deferred income taxes from previously realized tax repair deductions which resulted in the recognition of a $581 million Regulatory Asset and Regulatory Liability as of September 30, 2018. In addition, PSE&G agreed to the current flowback of tax benefits from ongoing tax repair deductions as realized which results in the recording of a Regulatory Asset upon flowback. For the years ended December 31, 2020 and 2019, PSE&G had provided $31 million and $58 million, respectively, in current tax repair flowbacks to customers. The recovery and amortization of the tax repair-related Deferred Income Tax Regulatory Assets will be determined in PSE&G’s subsequent base rate cases.
•Deferred Income Tax Regulatory Liabilities: These liabilities relate to amounts due to customers for excess deferred income taxes as a result of the reduction in the federal corporate income tax rate provided in the Tax Cuts and Jobs Act of 2017 (Tax Act), and accumulated deferred income taxes from previously realized distribution-related tax repair deductions. As part of its settlement with its regulators, PSE&G agreed to refund the excess deferred income taxes as follows:
•Unprotected distribution-related excess deferred income taxes are being refunded to customers over five years through PSE&G’s TAC mechanism as approved in its 2018 distribution base rate proceeding. As of December 31, 2020, the balance remaining to be flowed back to customers was approximately $520 million with the remaining flowback period through 2023.
•Protected distribution-related excess deferred income taxes are being refunded to customers over the remaining useful life of distribution property, plant and equipment through PSE&G’s TAC mechanism. As of December 31, 2020, the balance remaining to be flowed back to customers was approximately $933 million.
•Previously realized distribution-related tax repair deductions are being refunded to customers over ten years through PSE&G’s TAC mechanism. As of December 31, 2020, the balance remaining to be flowed back to customers was approximately $500 million through 2028.
•Protected transmission-related excess deferred income taxes are being refunded to customers over the remaining useful life of transmission property, plant and equipment through PSE&G’s transmission formula rate mechanism. As of December 31, 2020, the balance remaining to be flowed back to customers was approximately $940 million.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
•Unprotected transmission-related deferred income taxes were fully refunded to customers in 2019 and 2020.
•Deferred Storm Costs: Incremental costs incurred in the restoration and related costs from major storms in 2019 and 2020 for which PSE&G will seek recovery in its next base rate proceeding.
•Electric and Gas Cost of Removal: PSE&G accrues and collects in rates for the cost of removing, dismantling and disposing of its T&D assets upon retirement. The Regulatory Asset or Liability for non-legally required cost of removal represents the difference between amounts collected in rates and costs actually incurred.
•Electric Energy Costs-BGS: These costs represent the over or under recovered amounts associated with BGS, as approved by the BPU. Pursuant to BPU requirements, PSE&G serves as the supplier of last resort for electric customers within its service territory that are not served by another supplier. Pricing for those services are set by the BPU as a pass-through, resulting in no margin for PSE&G’s operations. Over or under recovered balances with interest are returned or recovered through monthly filings.
•Formula Rate True-Up: PSE&G’s transmission revenues are earned under a FERC-approved annual formula rate mechanism which provides for an annual filing of an estimated revenue requirement with rates effective January 1 of each year and a true-up to that estimate based on actual revenue requirements.
•Gas Costs-BGSS: These costs represent the over or under recovered amounts associated with BGSS, as approved by the BPU. Pursuant to BPU requirements, PSE&G serves as the supplier of last resort for gas customers within its service territory that are not served by another supplier. Pricing for those services are set by the BPU as a pass-through, resulting in no margin for PSE&G’s operations. Over or under collected balances are returned or recovered through an annual filing. Interest is accrued only on over recovered balances.
•GPRC: This amount represents costs of the over or under collected balances associated with various renewable energy and energy efficiency programs. PSE&G files annually with the BPU for recovery of amounts that include a return on and of its investment over the lives of the underlying investments and capital assets which range from five to ten years. Interest is accrued monthly on any over or under recovered balances. Components of the GPRC include: Carbon Abatement, Energy Efficiency Economic Stimulus Program (EEE), EEE Extension Program, EEE Extension II Program, Solar Generation Investment Program (Solar 4 All®), Solar 4 All® Extension, Solar 4 All® Extension II, Solar Loan II Program, Solar Loan III Program, Energy Efficiency (EE) 2017 Program, Clean Energy Future-Energy Efficiency (CEF-EE), and the Transition Renewable Energy Certificate (TRECs) Program.
•MGP Remediation Costs: Represents the low end of the range for the remaining environmental investigation and remediation program cleanup costs for MGPs that are probable of recovery in future rates. Once these costs are incurred, they are recovered through the RAC in the SBC over a seven year period with interest.
•New Jersey Clean Energy Program: The BPU approved future funding requirements for Energy Efficiency and Renewable Energy Programs. The BPU funding requirements are recovered through the SBC.
•Pension and OPEB Costs: Pursuant to the adoption of accounting guidance for employers’ defined benefit pension and OPEB plans, PSE&G recorded the unrecognized costs for defined benefit pension and other OPEB plans on the balance sheet as a Regulatory Asset. These costs represent net actuarial gains or losses and prior service costs which have not been expensed. These costs are amortized and recovered in future rates.
•RAC (Other SBC): Costs incurred to clean up MGPs which are recovered over seven years with interest through an annual filing.
•SBC: The SBC, as authorized by the BPU and the New Jersey Electric Discount and Energy Competition Act, includes costs related to PSE&G’s electric and gas business as follows: (1) the Universal Service Fund; (2) Energy Efficiency and Renewable Energy Programs; (3) Electric bad debt expense; and (4) the RAC for incurred MGP remediation expenditures. Over or under recovered balances with interest are to be returned or recovered through an annual filing.
•TAC: This represents the over or under collected balances associated with the return of excess accumulated deferred income taxes and the flowback of previously realized and current tax repair deductions under a mechanism approved by the BPU in PSE&G’s 2018 Base Rate Case Settlement. Over or under collected balances are returned or recovered through an annual filing. PSE&G includes a return component on the flowback of the excess accumulated deferred
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
income taxes and the previously realized tax repairs. Interest is accrued monthly on any over or under recovered balances.
•Unamortized Loss on Reacquired Debt and Debt Expense: Represents losses on reacquired long-term debt and expenses associated with issuances of new debt, which are recovered through rates over the remaining life of the debt.
•WNC: This represents the over or under recovery of gas margin which is filed annually with the BPU. The WNC requires PSE&G to calculate, at the end of each October-to-May period, the level by which margin revenues differed from what would have resulted if normal weather had occurred. Over recoveries are returned to customers in the next winter season while under recoveries (subject to an earnings cap) are recovered from customers in the next winter season.
•ZEC Liability: This represents amounts to be returned to customers for overcollections, including interest associated with the ZEC program whereby PSE&G purchases ZECs from eligible nuclear plants.
Significant 2019 and 2020 regulatory orders received and currently pending rate filings with the BPU by PSE&G are as follows:
•BGSS-In September 2020, the BPU provisionally approved PSE&G’s request to maintain the current BGSS rate of 32 cents. This rate is subject to final approval.
•CEF-Energy Cloud (EC) or Advanced Metering Infrastructure (AMI) Initiative-In January 2021, the BPU approved PSE&G’s CEF-EC filing to spend approximately $700 million in order to provide its 2.3 million electric customers with smart meters over the next four years. All of the capital and operating costs of the program will be recovered in PSE&G’s next base rate case, expected in the second half of 2024. From the start of the program until the commencement of new base rates, the return on and of the capital portion of the program will be included for recovery in those rates, as well as operating costs and stranded costs associated with the retirement of the existing meters.
•CEF-Electric Vehicles (EV)-In January 2021, the BPU approved a program for PSE&G to provide investments of $166 million for EV charging. All of the capital and operating costs of the program will be recovered in PSE&G’s next base rate case. From the start of the program until the commencement of new base rates, the return on and of the capital portion of the program will be included for recovery in those rates, as well as operating costs.
•CEF-EE, a New Component of the GPRC-In September 2020, the BPU approved PSE&G’s CEF-EE program, authorizing PSE&G to spend $1 billion in program costs. These costs will be recovered through the GPRC, with returns aligned with PSE&G’s most recent base rate case and recovered over a ten-year amortization period.
The approval also included a Conservation Incentive Program, a mechanism that will provide for recovery of lost electric and gas variable margin revenues. This mechanism is effective in June 2021 for electric and October 2021 for gas. PSE&G will suspend its gas WNC when the gas deferral period begins.
•COVID-19 Deferral-In July 2020, the BPU authorized regulated utilities in the State of New Jersey to create a COVID-19-related Regulatory Asset by deferring on their books and records the prudently incurred incremental costs related to COVID-19 as described above.
In October 2020, the BPU broadened the scope of the docket to include all pandemic issues in a generic proceeding that will include submission of public comments and consideration of, among other things, the timing and scope of current and planned clean energy programs; other utility filings and mechanisms; utility financial strength; customer concerns; regulatory compliance and priorities; and ensuring the continued provision of safe and adequate service at just and reasonable rates, while recognizing the ramifications from the COVID-19 pandemic.
PSE&G has made three quarterly filings as required by the BPU and recorded a Regulatory Asset of approximately $51 million in 2020 for net incremental costs, including $29 million for incremental bad debt expense associated with customer accounts receivable, which PSE&G believes are recoverable under the BPU order.
•Energy Strong Program II (ES II) Recovery Filing-In December 2020, PSE&G filed its first ES II electric only cost recovery petition seeking BPU approval to recover in electric rates the return on and of ES II electric investments placed in service through January 31, 2021. In February 2021, the petition was updated to reflect actual investments and costs, and requests an annual revenue increase of $13 million with rates effective no earlier than May 1, 2021. This matter is pending.
•Gas System Modernization Program II (GSMP II)-In July and November 2020, the BPU approved PSE&G’s GSMP II cost recovery petition requesting approximately $18 million and $20 million, respectively in gas revenues on
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
an annual basis, which included GSMP II investments in service as of February 29, 2020 and August 31,2020, respectively. The increases were effective July 16, 2020 and December 1, 2020.
In December 2020, PSE&G filed its next bi-annual GSMP II cost recovery petition seeking BPU approval to recover in gas base rates an estimated annual revenue increase of approximately $26 million effective June 1, 2021. This increase represents the return on and of GSMP II investments placed in service through February 28, 2021. This request will be updated in March 2021 for actual costs.
•GPRC-In January 2021, the BPU provisionally approved PSE&G’s 2020 GPRC cost recovery petition requesting recovery of approximately $67 million and $20 million in electric and gas revenues, respectively, on an annual basis with rates effective February 1, 2021.
•RAC-In December 2020, PSE&G filed its RAC 28 petition with the BPU seeking recovery of $35 million of net MGP remediation expenditures incurred from August 1, 2019 through July 31, 2020. This matter is pending.
In September 2020, the BPU approved PSE&G’s RAC 27 filing requesting recovery of approximately $53 million in net MGP remediation expenditures incurred from August 1, 2018 through July 31, 2019.
•SBC-In November 2020, PSE&G filed a petition to increase electric rates by approximately $76 million and decrease its gas rates by approximately $18 million, on an annual basis, in order to recover electric and gas costs incurred or expected to be incurred through February 28, 2022 under its EE and Renewable Energy and Social Programs. The increase to electric rates includes the impact of increased bad debt expense as a result of the negative economic impact of the ongoing coronavirus pandemic and moratorium on collections. This matter is pending.
•TAC-In October 2020, PSE&G made its annual 2020 TAC filing. The TAC allows for the flowback to customers of excess accumulated deferred income taxes resulting from the reduction of the federal income tax rates provided in the Tax Act as well as the accumulated deferred income taxes from previously realized tax repair deductions and tax benefits from future tax repair deductions as realized. The 2020 TAC filing, updated in January 2021, requests BPU approval to reduce electric revenues by approximately $26 million and increase gas revenues by $48 million on an annual basis starting January 1, 2021, including an update to the additional unprotected amounts to be flowed back as a result of the Private Letter Ruling (PLR) discussed below. This matter is pending.
In July 2020, the BPU gave final approval to PSE&G’s 2019 TAC filing that had been approved on a provisional basis in January 2020, with additional credits included in the final ruling. The final approval resulted in a reduction to electric and gas revenues of $25 million and $29 million, respectively, on an annual basis, effective July 16, 2020.
PSE&G received a PLR from the Internal Revenue Service (IRS) in April 2020 that concluded that certain excess deferred taxes previously classified as protected should be classified as unprotected. Unprotected excess deferred income taxes are not subject to the tax normalization rules allowing them to be refunded to customers sooner as agreed to with the BPU. As part of a procedural discovery to obtain the BPU’s final approval, PSE&G proposed that it change its current provisional TAC rates to increase the credit and start flowing back these unprotected amounts starting in July 2020 through December 31, 2024, which the BPU approved. This resulted in a total additional credit to electric and gas customers of $50 million and $46 million, respectively.
•Transition Incentive Program, a New Component of the GPRC-In 2019, the BPU approved an order establishing a Transition Incentive Program to serve as a bridge between the existing Solar Renewable Energy Certificate (SREC) program and a to-be-established successor incentive program and created a new incentive mechanism known as the Transition Renewable Energy Certificate (TRECs) Program. TRECs will be awarded to qualifying solar projects under the new program. In the TREC Order, the BPU directed the New Jersey EDCs to engage a TREC Administrator to acquire, on behalf of the EDCs, TRECs produced by eligible solar projects, which will be funded through a TREC charge to electric customers collected by the EDCs. The order allows the EDCs to recover their costs associated with the TREC program in an annual filing, subject to approval by the BPU.
In August 2020, the BPU approved PSE&G’s request for increased rates of approximately $23 million annually for recovery of its expected share of TREC costs. These costs will be recovered as a new component of PSE&G’s existing electric GPRC, which is updated on an annual basis.
•Transmission Formula Rates-In October 2020, PSE&G filed its 2020 Annual Transmission Formula Rate Update with FERC which will result in $119 million in increased annual transmission revenue effective January 1, 2021, subject to true-up.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
In June 2020, PSE&G filed its 2019 true-up adjustment pertaining to its transmission formula rates in effect for 2019. This filing resulted in an additional annual revenue requirement of $24 million more than the 2019 originally filed revenue.
In April 2020, the IRS issued a PLR to PSE&G concluding that certain excess deferred taxes previously classified as protected should be classified as unprotected. Unprotected excess deferred income taxes are not subject to the normalization rules allowing them to be refunded to customers sooner as agreed to with FERC and the BPU. In July 2020, FERC approved PSE&G’s request to allow the entire amount of these unprotected excess deferred income taxes be returned to customers in the 2019 true-up filing. As a result of the FERC approval, PSE&G recorded a revenue reduction of approximately $38 million in the third quarter of 2020, fully offset by a reduction in Income Tax Expense. The refund will be provided to transmission ratepayers as a reduction to the 2021 transmission rates.
•WNC-In November 2020, the BPU approved PSE&G’s updated WNC resetting the WNC rate to zero to eliminate any recovery of undercollected revenues from the warmer-than-normal 2019-2020 Winter Period. The updated filing eliminated the undercollection due to an earnings test limitation which was updated with actuals for the annual period ended September 2020 as stipulated in the filing. Previously, the BPU had approved a provisional rate effective October 1, 2020 for the collection of $10 million from customers over the 2020-2021 Winter Period. Approximately $2 million in October and November 2020 collections from the provisional rate will be refunded to customers with interest in the next annual filing.
•ZEC Program-In December 2020, the BPU approved PSE&G’s petition to refund a total of $6.2 million, including interest, for overcollections resulting from the ZEC program for the energy years ended May 31, 2020 and 2019. In 2020, PSE&G purchased approximately $154 million in ZECs, including interest, from the eligible nuclear plants selected by the BPU with the final payment made in August 2020. As a result of the collections and required ZEC payments, there was approximately $6 million in overcollected revenues, including interest, for the energy year ended May 31, 2020. This was combined with a $0.2 million overcollection from the prior period for a total of $6.2 million, with the credit to rates effective January 1, 2021.
Note 8. Leases
As of December 31, 2020, PSEG and its subsidiaries were both a lessee and a lessor in operating leases.
Lessee
PSE&G
PSE&G has operating leases for office space for customer service centers, rooftops and land for its Solar 4 All® facilities, equipment, vehicles and land for certain electric substations. These leases have remaining lease terms through 2040, some of which include options to extend the leases for up to five five-year terms. Some leases have fixed rent payments that have escalations based on certain indices, such as the CPI. Certain leases contain variable payments.
PSEG Power
PSEG Power has operating leases for buildings, land leases for its solar generating facilities, merchant transmission and equipment. These leases have remaining terms through 2055, some of which include options to extend the leases for up to seven five-year terms and certain other leases which include options to extend the leases for 15 to 20 year terms. Some leases have fixed rent payments that have escalations based on certain indices, such as the CPI. Certain leases contain variable payments.
Other
Services has operating leases for real estate and office equipment. These leases have remaining terms through 2030. Services’ lease for its headquarters, which ends in 2030, includes options to extend for two five-year terms.
Operating Lease Costs
The following amounts relate to total operating lease costs, including both amounts recognized in the Consolidated Statements of Operations during the years ended December 31, 2020 and 2019 and any amounts capitalized as part of the cost of another asset, and the cash flows arising from lease transactions.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PSE&G PSEG Power Other Total
Millions
Operating Lease Costs
Year Ended December 31, 2020
Long-term Lease Costs $ 26 $ 14 $ 14 $ 54
Short-term Lease Costs 38 7 - 45
Variable Lease Costs 2 20 9 31
Total Operating Lease Costs $ 66 $ 41 $ 23 $ 130
Year Ended December 31, 2020
Cash Paid for Amounts Included in the Measurement of Operating Lease Liabilities $ 17 $ 14 $ 14 $ 45
Weighted Average Remaining Lease Term in Years 12 14 10 11
Weighted Average Discount Rate 3.5 % 4.5 % 4.2 % 4.0 %
PSE&G PSEG Power Other Total
Millions
Operating Lease Costs
Year Ended December 31, 2019
Long-term Lease Costs $ 24 $ 13 $ 15 $ 52
Short-term Lease Costs 14 10 - 24
Variable Lease Costs 2 10 10 22
Total Operating Lease Costs $ 40 $ 33 $ 25 $ 98
Year Ended December 31, 2019
Cash Paid for Amounts Included in the Measurement of Operating Lease Liabilities $ 16 $ 11 $ 15 $ 42
Weighted Average Remaining Lease Term in Years 13 14 10 12
Weighted Average Discount Rate 3.6 % 4.4 % 4.2 % 4.1 %
Operating lease liabilities as of December 31, 2020 had the following maturities on an undiscounted basis:
PSE&G PSEG Power Other Total
Millions
2021 $ 16 $ 14 $ 15 $ 45
2022 13 14 15 42
2023 11 8 15 34
2024 10 3 15 28
2025 8 3 15 26
Thereafter 69 47 75 191
Total Minimum Lease Payments $ 127 $ 89 $ 150 $ 366
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following is a reconciliation of the undiscounted cash flows to the discounted Operating Lease Liabilities recognized on the Consolidated Balance Sheets:
As of December 31, 2020
PSE&G PSEG Power Other Total
Millions
Undiscounted Cash Flows $ 127 $ 89 $ 150 $ 366
Reconciling Amount due to Discount Rate (26) (27) (27) (80)
Total Discounted Operating Lease Liabilities $ 101 $ 62 $ 123 $ 286
As of December 31, 2019
PSE&G PSEG Power Other Total
Millions
Undiscounted Cash Flows $ 126 $ 100 $ 168 $ 394
Reconciling Amount due to Discount Rate (27) (28) (33) (88)
Total Discounted Operating Lease Liabilities $ 99 $ 72 $ 135 $ 306
As of December 31, 2020, the current portions of Operating Lease Liabilities included in Other Current Liabilities were $34 million, $13 million and $11 million for PSEG, PSE&G and PSEG Power, respectively. As of December 31, 2019, the current portions of Operating Lease Liabilities included in Other Current Liabilities were $33 million, $12 million and $10 million for PSEG, PSE&G and PSEG Power, respectively.
Lessor
PSEG Power
Certain of PSEG Power’s sales agreements related to its solar generating plants qualify as operating leases with remaining terms through 2043 with no extension terms. Lease income is based on solar energy generation; therefore, all rental income is variable under these leases. As of December 31, 2020, PSEG Power’s solar generating plants subject to these leases had a total carrying value of $376 million.
Other
Energy Holdings is the lessor in leveraged leases. See Note 9. Long-Term Investments and Note 10. Financing Receivables.
Energy Holdings is the lessor in two operating leases for domestic energy generation facilities with remaining terms through 2036, one of which has an optional renewal period. As of December 31, 2020, Energy Holdings’ property subject to these leases had a total carrying value of $83 million.
Energy Holdings was previously the lessor in operating leases for real estate assets which were sold in March 2020.
The following is the operating lease income for PSEG Power and Energy Holdings for the years ended December 31, 2020 and 2019:
PSEG Power Energy Holdings Total
Millions
Operating Lease Income
Year Ended December 31, 2020
Fixed Lease Income $ - $ 15 $ 15
Variable Lease Income 26 - 26
Total Operating Lease Income $ 26 $ 15 $ 41
Year Ended December 31, 2019
Fixed Lease Income $ - $ 22 $ 22
Variable Lease Income 23 - 23
Total Operating Lease Income $ 23 $ 22 $ 45
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Energy Holdings’ operating leases had the following minimum future fixed lease receipts as of December 31, 2020:
Millions
2021 $ 14
2022 14
2023 14
2024 14
2025 14
Thereafter 227
Total Minimum Future Lease Receipts $ 297
Note 9. Long-Term Investments
Long-Term Investments as of December 31, 2020 and 2019 included the following:
As of December 31,
2020 2019
Millions
PSE&G
Life Insurance and Supplemental Benefits $ 100 $ 111
Solar Loans 122 137
PSEG Power
Equity Method Investments (A) 64 66
Energy Holdings
Lease Investments 250 497
Equity Method Investments - 1
Total Long-Term Investments $ 536 $ 812
(A)During the three years ended December 31, 2020, 2019 and 2018, dividends from these investments were $15 million, $15 million and $16 million, respectively.
Leases
Energy Holdings, through several of its indirect subsidiaries, has investments in assets subject primarily to leveraged lease accounting. A leveraged lease is typically comprised of an investment by an equity investor and debt provided by a third-party debt investor. The debt is recourse only to the assets subject to lease and is not included on PSEG’s Consolidated Balance Sheets. As an equity investor, Energy Holdings’ equity investments in the leases are comprised of the total expected lease receivables over the lease terms plus the estimated residual values at the end of the lease terms, reduced for any income not yet earned on the leases. This amount is included in Long-Term Investments on PSEG’s Consolidated Balance Sheets. The more rapid depreciation of the leased property for tax purposes creates tax cash flow that will be repaid to the taxing authority in later periods. As such, the liability for such taxes due is recorded in Deferred Income Taxes on PSEG’s Consolidated Balance Sheets.
In September 2020, wholly owned subsidiaries of PSEG Energy Holdings L.L.C. (the Sellers) completed the sale of their ownership interests in the Powerton and Joliet generation facilities and related assets, including the assumption by the purchaser of related liabilities. The loss, net of taxes, resulting from the transaction was immaterial. In December 2020, the leveraged lease relating to our interest in the Shawville facilities was modified and extended. Accordingly, the Shawville leveraged lease was reclassified as an operating lease and the underlying assets were recorded in Property, Plant and Equipment. See Note 8. Leases.
In the second quarter of 2020, Energy Holdings completed its annual review of estimated residual values embedded in domestic energy leveraged leases and determined no impairments were necessary. During the second quarter of 2019, the outcome of Energy Holdings’ annual review indicated that the updated residual value estimate of the coal-fired Powerton lease was lower than the recorded residual value and the decline was deemed to be other than temporary as a result of expected future adverse market conditions. As a result, a pre-tax write-down of $58 million was reflected in Operating Revenues in 2019, calculated by comparing the gross investment in the leases before and after the revised residual estimates.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following table shows Energy Holdings’ gross and net lease investment as of December 31, 2020 and 2019.
As of December 31,
2020 2019
Millions
Lease Receivables (net of Non-Recourse Debt) $ 299 $ 498
Estimated Residual Value of Leased Assets 55 202
Total Investment in Rental Receivables 354 700
Unearned and Deferred Income (104) (203)
Gross Investments in Leases 250 497
Deferred Tax Liabilities (64) (328)
Net Investments in Leases $ 186 $ 169
The pre-tax income (loss) and income tax effects related to investments in leases, excluding gains and losses on sales and the impacts of the Tax Act, were as follows:
Years Ended December 31,
2020 2019 2018
Millions
Pre-Tax Income (Loss) from Leases $ 18 $ (39) $ 17
Income Tax Expense (Benefit) on Income (Loss) from Leases $ 2 $ (22) $ 6
Equity Method Investment
PSEG Power had a 50% ownership interest in Kalaeloa, a combined-cycle generation facility in Hawaii of $64 million and $66 million as of December 31, 2020 and 2019, respectively.
Note 10. Financing Receivables
PSE&G
PSE&G’s Solar Loan Programs are designed to help finance the installation of solar power systems throughout its electric service area. Interest income on the loans is recorded on an accrual basis. The loans are paid back with SRECs generated from the related installed solar electric system. PSE&G uses collection experience as a credit quality indicator for its Solar Loan Programs and conducts a comprehensive credit review for all prospective borrowers. As of December 31, 2020, none of the solar loans were impaired; however, in the event of a loan default or if a loan becomes impaired, the basis of the solar loan would be recovered through a regulatory recovery mechanism. As of December 31, 2020, none of the solar loans were delinquent and no loans are currently expected to become delinquent in light of the payment mechanism. Therefore, no current credit losses have been recorded for Solar Loan Programs I, II and III. A substantial portion of these amounts are noncurrent and reported in Long-Term Investments on PSEG’s and PSE&G’s Consolidated Balance Sheets. The following table reflects the outstanding loans by class of customer, none of which would be considered “non-performing.”
As of December 31,
Outstanding Loans by Class of Customer 2020 2019
Millions
Commercial/Industrial $ 145 $ 156
Residential 6 8
Total 151 164
Current Portion (included in Accounts Receivable) (29) (28)
Noncurrent Portion (included in Long-Term Investments) $ 122 $ 136
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The solar loans originated under three Solar Loan Programs are comprised as follows:
Programs Balance as of December 31, 2020 Funding Provided Residential Loan Term Non-Residential Loan Term
Millions
Solar Loan I $ 20 prior to 2013 10 years 15 years
Solar Loan II 69 prior to 2015 10 years 15 years
Solar Loan III 62 largely funded as of December 31, 2020 10 years 10 years
Total $ 151
The average life of loans paid in full is eight years, which is lower than the loan terms of 10 to 15 years due to the generation of SRECs being greater than expected and/or cash payments made to the loan. Payments on all outstanding loans were current as of December 31, 2020 and have an average remaining life of approximately four years.
Energy Holdings
Energy Holdings had net investments in assets subject to leveraged lease accounting of $186 million as of December 31, 2020 and $169 million as of December 31, 2019 (See Note 9. Long-Term Investments).
The corresponding receivables associated with the lease portfolio are reflected as follows, net of non-recourse debt. The ratings in the table represent the ratings of the entities providing payment assurance to Energy Holdings.
Lease Receivables, Net of
Non-Recourse Debt
Counterparties’ Credit Rating Standard & Poor’s (S&P) as of December 31, 2020 As of December 31, 2020
Millions
AA $ 9
A- 54
BBB+ to BBB 196
BB+ 40
Total $ 299
The “BB+” rating in the preceding table represents a lease receivable related to the Merrill Creek Reservoir. Metropolitan Edison Company (a subsidiary of First Energy) is the lease counterparty and fully guarantees the lease payments. As of December 31, 2020, the gross investment in this lease was $26 million ($20 million, net of deferred taxes).
PSEG recorded no credit losses in 2020 for the leveraged leases existing on December 31, 2020. Upon the occurrence of certain defaults, indirect subsidiaries of Energy Holdings would exercise their rights and seek recovery of their investment, potentially including stepping into the lease directly to protect their investments. While these actions could ultimately protect or mitigate the loss of value, they could require the use of significant capital and trigger certain material tax obligations which could, for certain leases, wholly or partially be mitigated by tax indemnification claims against the counterparty. A bankruptcy of a lessee would likely delay and potentially limit any efforts on the part of the lessors to assert their rights upon default and could delay the monetization of claims.
Note 11. Trust Investments
NDT Fund
In accordance with NRC regulations, entities owning an interest in nuclear generating facilities are required to determine the costs and funding methods necessary to decommission such facilities upon termination of operation. As a general practice, each nuclear owner places funds in independent external trust accounts it maintains to provide for decommissioning. PSEG Power is required to file periodic reports with the NRC demonstrating that its NDT Fund meets the formula-based minimum NRC funding requirements. PSEG Power maintains an external master NDT to fund its share of decommissioning costs for its five nuclear facilities upon their respective termination of operation. The trust contains two separate funds: a qualified fund and a non-qualified fund. Section 468A of the Internal Revenue Code limits the amount of money that can be contributed into a qualified fund. PSEG Power’s share of decommissioning costs related to its five nuclear units was estimated to be between $2.8 billion and $3.0 billion, including contingencies. The liability for decommissioning recorded on a discounted basis as of
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2020 was approximately $852 million and is included in the Asset Retirement Obligation. The funds are managed by third-party investment managers who operate under investment guidelines developed by PSEG Power.
The following tables show the fair values and gross unrealized gains and losses for the securities held in the NDT Fund.
As of December 31, 2020
Cost Gross
Unrealized
Gains Gross
Unrealized
Losses Fair
Value
Millions
Equity Securities
Domestic $ 519 $ 305 $ (3) $ 821
International 388 152 (9) 531
Total Equity Securities 907 457 (12) 1,352
Available-for-Sale Debt Securities
Government 555 27 (1) 581
Corporate 528 39 (1) 566
Total Available-for-Sale Debt Securities 1,083 66 (2) 1,147
Total NDT Fund Investments (A) $ 1,990 $ 523 $ (14) $ 2,499
(A) The NDT Fund Investments table excludes foreign currency of $2 million as of December 31, 2020,
which is part of the NDT Fund.
As of December 31, 2019
Cost Gross
Unrealized
Gains Gross
Unrealized
Losses Fair
Value
Millions
Equity Securities
Domestic $ 425 $ 238 $ (4) $ 659
International 400 103 (11) 492
Total Equity Securities 825 341 (15) 1,151
Available-for-Sale Debt Securities
Government 563 16 (2) 577
Corporate 470 17 (1) 486
Total Available-for-Sale Debt Securities 1,033 33 (3) 1,063
Total NDT Fund Investments (A) $ 1,858 $ 374 $ (18) $ 2,214
(A) The NDT Fund Investments table excludes foreign currency of $2 million as of December 31, 2019, which is part of the NDT Fund.
Net unrealized gains on debt securities of $37 million (after-tax) were included in Accumulated Other Comprehensive Loss on PSEG’s and PSEG Power’s Consolidated Balance Sheets as of December 31, 2020. An impairment of debt securities of $(3) million was included in Net Gains (Losses) on Trust Investments in PSEG Power’s Consolidated Statement of Operations for the year ended December 31, 2020. The portion of net unrealized gains recognized during 2020 related to equity securities still held at the end of December 31, 2020 was $184 million.
The amounts in the preceding tables do not include receivables and payables for NDT Fund transactions which have not settled at the end of each period. Such amounts are included in Accounts Receivable and Accounts Payable on the Consolidated Balance Sheets as shown in the following table.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
As of December 31,
2020 2019
Millions
Accounts Receivable $ 11 $ 11
Accounts Payable $ 12 $ 11
The following table shows the value of securities in the NDT Fund that have been in an unrealized loss position for less than and greater than 12 months.
As of December 31, 2020 As of December 31, 2019
Less Than 12
Months Greater Than 12
Months Less Than 12
Months Greater Than 12
Months
Fair
Value Gross
Unrealized
Losses Fair
Value Gross
Unrealized
Losses Fair
Value Gross
Unrealized
Losses Fair
Value Gross
Unrealized
Losses
Millions
Equity Securities (A)
Domestic $ 23 $ (2) $ 6 $ (1) $ 21 $ (1) $ 6 $ (3)
International 26 (2) 27 (7) 28 (2) 34 (9)
Total Equity Securities 49 (4) 33 (8) 49 (3) 40 (12)
Available-for-Sale Debt Securities
Government (B) 72 (1) - - 99 (2) 30 -
Corporate (C) 31 (1) 7 - 49 - 12 (1)
Total Available-for-Sale Debt Securities 103 (2) 7 - 148 (2) 42 (1)
NDT Trust Investments $ 152 $ (6) $ 40 $ (8) $ 197 $ (5) $ 82 $ (13)
(A)Equity Securities-Investments in marketable equity securities within the NDT Fund are primarily in common stocks within a broad range of industries and sectors. Unrealized gains and losses on these securities are recorded in Net Income.
(B)Debt Securities (Government)-Unrealized gains and losses on these securities are recorded in Accumulated Other Comprehensive Income (Loss). The unrealized losses on PSEG Power’s NDT investments in U.S. Treasury obligations and Federal Agency mortgage-backed securities were caused by interest rate changes. PSEG Power also has investments in municipal bonds. It is not expected that these securities will settle for less than their amortized cost. PSEG Power does not intend to sell these securities nor will it be more-likely-than-not required to sell before recovery of their amortized cost. PSEG Power did not recognize credit losses for U.S. Treasury obligations and Federal Agency mortgage-backed securities because these investments are guaranteed by the U.S. government or an agency of the U.S. government. PSEG Power did not recognize credit losses for municipal bonds because they are primarily investment grade securities.
(C)Debt Securities (Corporate)-Unrealized gains and losses on these securities are recorded in Accumulated Other Comprehensive Income (Loss). Unrealized losses were due to market declines. It is not expected that these securities would settle for less than their amortized cost. PSEG Power does not intend to sell these securities nor will it be more-likely-than-not required to sell before recovery of their amortized cost. PSEG Power did not recognize credit losses for these corporate bonds because they are primarily investment grade securities.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The proceeds from the sales of and the net gains (losses) on securities in the NDT Fund were:
Years Ended December 31,
2020 2019 2018
Millions
Proceeds from Sales (A) $ 2,031 $ 1,614 $ 1,398
Net Realized Gains (Losses):
Gross Realized Gains $ 214 $ 107 $ 121
Gross Realized Losses (94) (53) (51)
Net Realized Gains (Losses) on NDT Fund (B) 120 54 70
Unrealized Gains (Losses) on Equity Securities in NDT Fund 120 196 (209)
Impairment of Available-for-Sale Debt Securities (C) (3) - -
Net Gains (Losses) on NDT Fund Investments $ 237 $ 250 $ (139)
(A)Includes activity in accounts related to the liquidation of funds being transitioned to new managers.
(B)The cost of these securities was determined on the basis of specific identification.
(C)PSEG Power recognized an impairment of available-for-sale debt securities that it intends to sell. PSEG Power’s policy is to sell all such securities that are rated below investment grade.
The NDT Fund debt securities held as of December 31, 2020 had the following maturities:
Time Frame Fair Value
Millions
Less than one year $ 20
1 - 5 years 301
6 - 10 years 202
11 - 15 years 81
16 - 20 years 79
Over 20 years 464
Total NDT Available-for-Sale Debt Securities $ 1,147
PSEG Power periodically assesses individual debt securities whose fair value is less than amortized cost to determine whether the investments are impaired. For these securities, management considers its intent to sell or requirement to sell a security prior to expected recovery. In those cases where a sale is expected, any impairment would be recorded through earnings. For fixed income securities where there is no intent to sell or likely requirement to sell, management evaluates whether credit loss is a component of the impairment. If so, that portion is recorded through earnings while the noncredit loss component is recorded through Accumulated Other Comprehensive Income (Loss). Any subsequent recoveries of the noncredit loss component of the impairment would be recorded through Accumulated Other Comprehensive Income (Loss). Any subsequent recoveries of the credit loss component would be recognized through earnings. The assessment of fair market value compared to cost is applied on a weighted average basis taking into account various purchase dates and initial cost of the securities.
Rabbi Trust
PSEG maintains certain unfunded nonqualified benefit plans to provide supplemental retirement and deferred compensation benefits to certain key employees. Certain assets related to these plans have been set aside in a grantor trust commonly known as a “Rabbi Trust.”
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following tables show the fair values, gross unrealized gains and losses and amortized cost basis for the securities held in the Rabbi Trust.
As of December 31, 2020
Cost Gross
Unrealized
Gains Gross
Unrealized
Losses Fair
Value
Millions
Equity Securities
Domestic $ 21 $ 10 $ - $ 31
International - - - -
Total Equity Securities 21 10 - 31
Available-for-Sale Debt Securities
Government 94 6 - 100
Corporate 123 12 - 135
Total Available-for-Sale Debt Securities 217 18 - 235
Total Rabbi Trust Investments $ 238 $ 28 $ - $ 266
As of December 31, 2019
Cost Gross
Unrealized
Gains Gross
Unrealized
Losses Fair
Value
Millions
Equity Securities
Domestic $ 21 $ 7 $ - $ 28
International - - - -
Total Equity Securities 21 7 - 28
Available-for-Sale Debt Securities
Government 100 4 - 104
Corporate 107 7 - 114
Total Available-for-Sale Debt Securities 207 11 - 218
Total Rabbi Trust Investments $ 228 $ 18 $ - $ 246
Net unrealized gains on debt securities of $13 million (after-tax) were included in Accumulated Other Comprehensive Loss on PSEG’s Consolidated Balance Sheet as of December 31, 2020. The portion of net unrealized gains recognized during 2020 related to equity securities still held at the end of December 31, 2020 was $4 million.
The amounts in the preceding tables do not include receivables and payables for Rabbi Trust Fund transactions which have not settled at the end of each period. Such amounts are included in Accounts Receivable and Accounts Payable on the Consolidated Balance Sheets as shown in the following table.
As of December 31,
2020 2019
Millions
Accounts Receivable $ 1 $ 2
Accounts Payable $ 1 $ -
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following table shows the value of securities in the Rabbi Trust Fund that have been in an unrealized loss position for less than and greater than 12 months:
As of December 31, 2020 As of December 31, 2019
Less Than 12
Months Greater Than 12
Months Less Than 12
Months Greater Than 12
Months
Fair
Value Gross
Unrealized
Losses Fair
Value Gross
Unrealized
Losses Fair
Value Gross
Unrealized
Losses Fair
Value Gross
Unrealized
Losses
Millions
Available-for-Sale Debt Securities
Government (A) $ 19 $ - $ - $ - $ 26 $ - $ 3 $ -
Corporate (B) 2 - 1 - 11 - 2 -
Total Available-for-Sale Debt Securities 21 - 1 - 37 - 5 -
Rabbi Trust Investments $ 21 $ - $ 1 $ - $ 37 $ - $ 5 $ -
(A)Debt Securities (Government)-Unrealized gains and losses on these securities are recorded in Accumulated Other Comprehensive Income (Loss). The unrealized losses on PSEG’s Rabbi Trust investments in U.S. Treasury obligations and Federal Agency mortgage-backed securities were caused by interest rate changes. PSEG also has investments in municipal bonds. It is not expected that these securities will settle for less than their amortized cost. PSEG does not intend to sell these securities nor will it be more-likely-than-not required to sell before recovery of their amortized cost. PSEG did not recognize credit losses for U.S. Treasury obligations and Federal Agency mortgage-backed securities because these investments are guaranteed by the U.S. government or an agency of the U.S. government. PSEG did not recognize credit losses for municipal bonds because they are primarily investment grade securities.
(B)Debt Securities (Corporate)-Unrealized gains and losses on these securities are recorded in Accumulated Other Comprehensive Income (Loss). Unrealized losses were due to market declines. It is not expected that these securities would settle for less than their amortized cost. PSEG does not intend to sell these securities nor will it be more-likely-than-not required to sell before recovery of their amortized cost. PSEG did not recognize credit losses for these corporate bonds because they are primarily investment grade.
The proceeds from the sales of and the net gains (losses) on securities in the Rabbi Trust Fund were:
Years Ended December 31,
2020 2019 2018
Millions
Proceeds from Rabbi Trust Sales (A) $ 203 $ 173 $ 103
Net Realized Gains (Losses):
Gross Realized Gains $ 19 $ 7 $ 2
Gross Realized Losses (6) (3) (4)
Net Realized Gains (Losses) on Rabbi Trust (B) 13 4 (2)
Unrealized Gains (Losses) on Equity Securities in Rabbi Trust 3 6 (2)
Net Gains (Losses) on Rabbi Trust Investments $ 16 $ 10 $ (4)
(A)Includes activity in accounts related to the liquidation of funds being transitioned to new managers.
(B)The cost of these securities was determined on the basis of specific identification.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The Rabbi Trust debt securities held as of December 31, 2020 had the following maturities:
Time Frame Fair Value
Millions
Less than one year $ 5
1 - 5 years 39
6 - 10 years 30
11 - 15 years 12
16 - 20 years 30
Over 20 years 119
Total Rabbi Trust Available-for-Sale Debt Securities $ 235
PSEG periodically assesses individual debt securities whose fair value is less than amortized cost to determine whether the investments are considered to be impaired. For these securities, management considers its intent to sell or requirement to sell a security prior to expected recovery. In those cases where a sale is expected, any impairment would be recorded through earnings. For fixed income securities where there is no intent to sell or likely requirement to sell, management evaluates whether credit loss is a component of the impairment. If so, that portion is recorded through earnings while the noncredit loss component is recorded through Accumulated Other Comprehensive Income (Loss). Any subsequent recoveries of the noncredit loss component of the impairment would be recorded through Accumulated Other Comprehensive Income (Loss). Any subsequent recoveries of the credit loss component would be recognized through earnings. The assessment of fair market value compared to cost is applied on a weighted average basis taking into account various purchase dates and initial cost of the securities.
The fair value of the Rabbi Trust related to PSEG, PSE&G and PSEG Power are detailed as follows:
As of December 31, As of December 31,
2020 2019
Millions
PSE&G $ 51 $ 48
PSEG Power 66 62
Other 149 136
Total Rabbi Trust Investments $ 266 $ 246
Note 12. Goodwill and Other Intangibles
In 2019, PSEG Power determined its fair value using a market-based enterprise valuation technique. Based on the results of the annual impairment test, PSEG Power determined that its entire goodwill was impaired and recorded a loss of $16 million in O&M Expense. The decrease in the fair value was primarily due to the continued decline in wholesale power market pricing.
As of December 31, 2020 and 2019, PSEG Power had intangible assets of $158 million and $149 million, respectively, related to emissions allowances and RECs. Emissions allowances and RECs are recorded at cost and evaluated for impairment at least annually. Emissions expense includes impairments of emissions allowances, if any, and costs for emissions, which is recorded as emissions occur. As load is served under contracts requiring energy from renewable sources, the related expense is recorded.
The changes to PSEG Power’s intangible assets during 2019 and 2020 are as follows:
Emissions Allowances RECs Total Other Intangibles
Millions
Balance as of January 1, 2019 $ 84 $ 59 $ 143
Retirements (6) (83) (89)
Purchases 26 72 98
Sales and Transfers, net - (3) (3)
Balance as of December 31, 2019 $ 104 $ 45 $ 149
Retirements (9) (93) (102)
Purchases 17 94 111
Balance as of December 31, 2020 $ 112 $ 46 $ 158
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 13. Asset Retirement Obligations (AROs)
PSEG, PSE&G and PSEG Power recognize liabilities for the expected cost of retiring long-lived assets for which a legal obligation exists to remove or dispose of an asset or some component of an asset at retirement. 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. PSEG Power accretes the ARO liability to reflect the passage of time with the corresponding expense recorded in O&M. 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.
PSE&G has conditional AROs primarily for legal obligations related to the removal of treated wood poles and the requirement to seal natural gas pipelines at all sources of gas when the pipelines are no longer in service. PSE&G does not record an ARO for its protected steel and poly-based natural gas lines, as management believes that these categories of gas lines have an indeterminable life.
PSEG Power’s ARO liability primarily relates to the decommissioning of its nuclear power plants in accordance with NRC requirements. PSEG Power has an independent external trust that is intended to fund decommissioning of its nuclear facilities upon termination of operation. For additional information, see Note 11. Trust Investments. PSEG Power also identified conditional AROs primarily related to PSEG Power’s fossil generation units and solar facilities, including liabilities for removal of asbestos, ash ponds, stored hazardous liquid material and underground storage tanks from industrial power sites, and demolition of certain plants, and the restoration of the sites at which they reside, when the plants are no longer in service. To estimate the fair value of its AROs, PSEG Power uses a probability weighted, discounted cash flow model which, on a unit by unit basis, considers multiple outcome scenarios that include significant estimates and assumptions, and are based on third-party decommissioning cost estimates, cost escalation rates, inflation rates and discount rates.
Updated cost studies are obtained triennially unless new information necessitates more frequent updates. The most recent cost study was done in 2018. When assumptions are revised to calculate fair values of existing AROs, generally, the ARO balance and corresponding long-lived asset are adjusted which impact the amount of accretion and depreciation expense recognized in future periods. For PSE&G, Regulatory Assets and Regulatory Liabilities result when accretion and amortization are adjusted to match rates established by regulators resulting in the regulatory deferral of any gain or loss.
The changes to the ARO liabilities for PSEG, PSE&G and PSEG Power during 2019 and 2020 are presented in the following table:
PSEG PSE&G PSEG Power Other
Millions
ARO Liability as of January 1, 2019 $ 1,063 $ 302 $ 758 $ 3
Liabilities Settled (19) (18) (1) -
Liabilities Incurred 3 1 2 -
Accretion Expense 40 - 40 -
Accretion Expense Deferred and Recovered in Rate Base (A) 16 16 - -
Revision to Present Values of Estimated Cash Flows (16) 2 (18) -
ARO Liability as of December 31, 2019 $ 1,087 $ 303 $ 781 $ 3
Liabilities Settled (9) (7) (2) -
Accretion Expense 42 - 42 -
Accretion Expense Deferred and Recovered in Rate Base (A) 17 17 - -
Revision to Present Values of Estimated Cash Flows 75 1 74 -
ARO Liability as of December 31, 2020 $ 1,212 $ 314 $ 895 $ 3
(A)Not reflected as expense in Consolidated Statements of Operations
In early 2020, the NRC approved Peach Bottom’s second license extension for both units. Concurrent with the license extensions, PSEG Power has extended the useful life of the asset to match the 80-year life expectation and reassessed the related Asset Retirement Cost (ARC) and ARO assumptions. This resulted in an increase to the ARC asset and ARO liability of $74 million, primarily due to lower discount rates offset by a longer discounting period as a result of the Peach Bottom units’ longer expected useful life. In addition, PSEG Power reviewed its probabilities of early retirement on its nuclear units and concluded that no adjustments were necessary as of December 31, 2020.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
In 2019, PSEG Power’s decrease of $18 million was primarily due to the sale of its interests in the Keystone and Conemaugh units. These changes had an immaterial impact in PSEG Power’s Consolidated Statement of Operations. See Note 4. Early Plant Retirements/Asset Dispositions for additional information.
Note 14. Pension, Other Postretirement Benefits (OPEB) and Savings Plans
PSEG sponsors and Services administers qualified and nonqualified pension plans and OPEB plans covering PSEG’s and its participating affiliates’ current and former employees who meet certain eligibility criteria. PSEG’s qualified pension plans consist of two qualified defined benefit pension plans, Pension Plan and Pension Plan II. Each of the qualified pension plans include a Final Average Pay and two Cash Balance components. In addition, represented and non-represented employees are eligible for participation in PSEG’s two defined contribution plans.
PSEG, PSE&G and PSEG Power are required to record the under or over funded positions of their defined benefit pension and OPEB plans on their respective balance sheets. Such funding positions of each PSEG company are required to be measured as of the date of its respective year-end Consolidated Balance Sheets. For underfunded plans, the liability is equal to the difference between the plan’s benefit obligation and the fair value of plan assets. For defined benefit pension plans, the benefit obligation is the projected benefit obligation. For OPEB plans, the benefit obligation is the accumulated postretirement benefit obligation. In addition, GAAP requires that the total unrecognized costs for defined benefit pension and OPEB plans be recorded as an after-tax charge to Accumulated Other Comprehensive Income (Loss), a separate component of Stockholders’ Equity. However, for PSE&G, because the amortization of the unrecognized costs is being collected from customers, the accumulated unrecognized costs are recorded as a Regulatory Asset. The unrecognized costs represent actuarial gains or losses and prior service costs which have not been expensed.
For PSE&G, the Regulatory Asset is amortized and recorded as net periodic pension cost in the Consolidated Statements of Operations. For PSEG Power, the charge to Accumulated Other Comprehensive Income (Loss) is amortized and recorded as net periodic pension cost in the Consolidated Statements of Operations.
In late June 2019, PSEG approved a plan amendment to its qualified pension plan, effective July 1, 2019. The amendment involved the spin-off of predominantly active participants from the existing qualified pension plan (Pension Plan) into a new qualified pension plan (Pension Plan II). Benefits offered to the plan participants remain unchanged. The existing plan’s pension benefit obligations, as well as the asset values, were remeasured as of July 1, 2019 as a result of the amendment. As of July 1, 2019, the weighted average discount rate for the combined plans decreased from 4.41% to 3.65% and the expected long-term rate of return on plan assets remained at 7.80%. Actuarial gains and losses associated with the Pension Plan will be amortized over the average remaining life expectancy of the inactive participants (as opposed to the average remaining service of active participants prior to the plan being split). Actuarial gains and losses associated with Pension Plan II will be amortized over the average remaining service of active participants. The combined remeasured qualified pension plans’ projected benefit obligation as of July 1, 2019 was $6.4 billion.
Amounts for Servco are not included in any of the following pension and OPEB benefit information for PSEG and its affiliates but rather are separately disclosed later in this note.
The following table provides a roll-forward of the changes in the benefit obligation and the fair value of plan assets during each of the two years in the periods ended December 31, 2020 and 2019. It also provides the funded status of the plans and the amounts recognized and amounts not recognized on the Consolidated Balance Sheets at the end of both years.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Pension Benefits Other Benefits
2020 2019 2020 2019
Millions
Change in Benefit Obligation
Benefit Obligation at Beginning of Year (A) $ 6,892 $ 5,921 $ 1,285 $ 1,203
Service Cost 141 123 9 10
Interest Cost 192 218 34 45
Actuarial (Gain) Loss (B) 615 955 32 109
Gross Benefits Paid (333) (325) (50) (82)
Plan Amendments - - (4) -
Benefit Obligation at End of Year (A) $ 7,507 $ 6,892 $ 1,306 $ 1,285
Change in Plan Assets
Fair Value of Assets at Beginning of Year $ 5,929 $ 5,120 $ 540 $ 488
Actual Return on Plan Assets 761 1,122 70 107
Employer Contributions 11 12 4 27
Gross Benefits Paid (333) (325) (50) (82)
Fair Value of Assets at End of Year $ 6,368 $ 5,929 $ 564 $ 540
Funded Status
Funded Status (Plan Assets less Benefit Obligation) $ (1,139) $ (963) $ (742) $ (745)
Additional Amounts Recognized in the Consolidated Balance Sheets
Current Accrued Benefit Cost $ (11) $ (11) $ (12) $ (11)
Noncurrent Accrued Benefit Cost (1,128) (952) (730) (734)
Amounts Recognized $ (1,139) $ (963) $ (742) $ (745)
Additional Amounts Recognized in Accumulated Other Comprehensive Income (Loss), Regulated Assets and Deferred Assets (C)
Prior Service Credit $ - $ (10) $ (310) $ (433)
Net Actuarial Loss 2,354 2,150 364 409
Total $ 2,354 $ 2,140 $ 54 $ (24)
(A)Represents projected benefit obligation for pension benefits and the accumulated postretirement benefit obligation for other benefits. The vested benefit obligation is the actuarial present value of the vested benefits to which the employee is currently entitled but based on the employee’s expected date of separation or retirement.
(B)For pension benefits, the net actuarial loss was primarily due to a decrease in the discount rate. For OPEB, the net actuarial loss was primarily due to a decrease in the discount rate, partially offset by actuarial gains driven by lower than expected claims experience.
(C)Includes $760 million ($545 million, after-tax) and $695 million ($499 million, after-tax) in Accumulated Other Comprehensive Loss related to Pension and OPEB as of December 31, 2020 and 2019, respectively. Also includes Regulatory Assets of $1,489 million and Deferred Assets of $159 million as of December 31, 2020 and Regulatory Assets of $1,284 million and Deferred Assets of $137 million as of December 31, 2019.
The pension benefits table above provides information relating to the funded status of the qualified and nonqualified pension and OPEB plans on an aggregate basis. As of December 31, 2020, PSEG had funded approximately 85% of its projected pension benefit obligation. This percentage does not include $266 million of assets in the Rabbi Trust as of December 31, 2020 which were used partially to fund the nonqualified pension plans. As of December 31, 2020, the nonqualified pension plans included in the projected benefit obligation in the above table were $182 million.
Accumulated Benefit Obligation
The accumulated benefit obligation for all PSEG’s defined benefit pension plans was $7.3 billion as of December 31, 2020 and $6.7 billion as of December 31, 2019.
The following table provides the components of net periodic benefit cost relating to all qualified and nonqualified pension and OPEB plans on an aggregate basis for PSEG, excluding Servco for the years ended December 31, 2020, 2019 and 2018.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Amounts shown do not reflect the impacts of capitalization and co-owner allocations. Only the service cost component is eligible for capitalization, when applicable.
Pension Benefits Years Ended December 31, Other Benefits Years Ended December 31,
2020 2019 2018 2020 2019 2018
Millions
Components of Net Periodic Benefit (Credits) Costs
Service Cost (included in O&M Expense) $ 141 $ 123 $ 130 $ 9 $ 10 $ 18
Non-Service Components of Pension and OPEB (Credits) Costs
Interest Cost 192 218 208 34 45 66
Expected Return on Plan Assets (443) (408) (441) (39) (36) (41)
Amortization of Net
Prior Service Credit (10) (18) (18) (128) (128) (1)
Actuarial Loss 92 96 85 47 50 64
Non-Service Components of Pension and OPEB (Credits) Costs (169) (112) (166) (86) (69) 88
Total Benefit (Credits) Costs $ (28) $ 11 $ (36) $ (77) $ (59) $ 106
Pension costs and OPEB costs for PSEG, PSE&G and PSEG Power are detailed as follows:
Pension Benefits
Years Ended December 31, Other Benefits
Years Ended December 31,
2020 2019 2018 2020 2019 2018
Millions
PSE&G $ (27) $ - $ (31) $ (76) $ (62) $ 68
PSEG Power (5) 4 (9) - 3 32
Other 4 7 4 (1) - 6
Total Benefit (Credits) Costs $ (28) $ 11 $ (36) $ (77) $ (59) $ 106
The following table provides the pre-tax changes recognized in Accumulated Other Comprehensive Income (Loss), Regulatory Assets and Deferred Assets:
Pension OPEB
2020 2019 2020 2019
Millions
Net Actuarial (Gain) Loss in Current Period $ 296 $ 241 $ 2 $ 39
Amortization of Net Actuarial Gain (Loss) (92) (96) (47) (50)
Prior Service Cost (Credit) in Current Period - - (5) -
Amortization of Prior Service Credit 10 18 128 128
Total $ 214 $ 163 $ 78 $ 117
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following assumptions were used to determine the benefit obligations and net periodic benefit costs:
Pension Benefits Other Benefits
2020 2019 2018 2020 2019 2018
Weighted-Average Assumptions Used to Determine Benefit Obligations as of December 31
Discount Rate 2.61 % 3.30 % 4.41 % 2.46 % 3.20 % 4.31 %
Rate of Compensation Increase 4.40 % 3.90 % 3.90 % 4.40 % 3.90 % 3.90 %
Cash Balance Interest Crediting Rate 6.00 % 6.00 % 6.00 % N/A N/A N/A
Weighted-Average Assumptions Used to Determine Net Periodic Benefit Cost for Years Ended December 31
Discount Rate 3.30 % 4.41 % 3.73 % 3.20 % 4.31 % 3.76 %
Service Cost Interest Rate 3.49 % 4.58 % 3.88 % 3.50 % 4.48 % 3.90 %
Interest Cost Interest Rate 2.87 % 4.03 % 3.35 % 2.87 % 3.91 % 3.39 %
Expected Return on Plan Assets 7.70 % 7.80 % 7.80 % 7.70 % 7.79 % 7.80 %
Rate of Compensation Increase 3.90 % 3.90 % 3.90 % 3.90 % 3.90 % 3.90 %
Cash Balance Interest Crediting Rate 6.00 % 6.00 % 6.00 % N/A N/A N/A
Assumed Health Care Cost Trend Rates as of December 31
Health Care Costs
Immediate Rate 6.37 % 6.68 % 7.28 %
Ultimate Rate 4.75 % 4.75 % 4.75 %
Year Ultimate Rate Reached 2029 2029 2026
Plan Assets
The investments of pension and OPEB plans are held in a trust account by the Trustee and consist of an undivided interest in an investment account of the Master Trust. The investments in the pension and OPEB plans are measured at fair value within a hierarchy that prioritizes the inputs to fair value measurements into three levels. See Note 19. Fair Value Measurements for more information on fair value guidance. Use of the Master Trust permits the commingling of pension plan assets and OPEB plan assets for investment and administrative purposes. Although assets of the plans are commingled in the Master Trust, the Trustee maintains supporting records for the purpose of allocating the net gain or loss of the investment account to the respective participating plans. The net investment income of the investment assets is allocated by the Trustee to each participating plan based on the relationship of the interest of each plan to the total of the interests of the participating plans. As of December 31, 2020, the pension plan interest and OPEB plan interest in such assets of the Master Trust were approximately 92% and 8%, respectively.
The following tables present information about the investments measured at fair value on a recurring basis as of December 31, 2020 and 2019, including the fair value measurements and the levels of inputs used in determining those fair values.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Recurring Fair Value Measurements as of December 31, 2020
Quoted Market Prices
for Identical Assets Significant Other
Observable Inputs Significant
Unobservable Inputs
Description Total (Level 1) (Level 2) (Level 3)
Millions
Cash Equivalents (A) $ 85 $ 85 $ - $ -
Equity Securities
Common Stock (B) 1,763 1,763 - -
Commingled (C) 1,964 1,025 939 -
Preferred Stock (B) 10 10 - -
Other (D) 1 1 - -
Debt Securities (E)
U.S. Treasury 419 - 419 -
Government-Other 258 - 258 -
Corporate 823 - 823 -
Commingled 4 4 - -
Subtotal Fair Value $ 5,327 $ 2,888 $ 2,439 $ -
Measured at net asset value practical expedient
Commingled-Equities (F) 1,283
Real Estate Investment (G) 306
Private Equity (H) 5
Total Fair Value (I) $ 6,921
Recurring Fair Value Measurements as of December 31, 2019
Quoted Market Prices
for Identical Assets Significant Other
Observable Inputs Significant
Unobservable Inputs
Description Total (Level 1) (Level 2) (Level 3)
Millions
Cash Equivalents (A) $ 104 $ 103 $ 1 $ -
Equity Securities
Common Stock (B) 1,487 1,487 - -
Commingled (C) 1,707 1,042 665 -
Preferred Stock (B) 19 19 - -
Other (D) 3 3 - -
Debt Securities (E)
U.S. Treasury 544 - 544 -
Government-Other 284 - 284 -
Corporate 837 - 837 -
Commingled 3 3 - -
Other (Future Contracts) (3) (3) - -
Subtotal Fair Value $ 4,985 $ 2,654 $ 2,331 $ -
Measured at net asset value practical expedient
Commingled-Equities (F) 1,154
Real Estate Investment (G) 302
Private Equity (H) 8
Total Fair Value (I) $ 6,449
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(A)The Collective Investment Fund publishes a daily net asset value (NAV) which participants may use for daily redemptions without restrictions (Level 1). Certain temporary investments are valued using inputs such as time-to-maturity, coupon rate, quality rating and current yield (Level 2).
(B)Common stocks and preferred stocks are measured using observable data in active markets and considered Level 1.
(C)Commingled Funds that allow daily redemption at their daily published NAV without restrictions are classified as Level 1. Commingled Funds that publish daily NAV but with certain near-term redemption restrictions which prevent redemption at the published daily NAV are classified as Level 2.
(D)Investment in a publicly traded limited partnership.
(E)Debt securities include mainly investment grade corporate and municipal bonds, U.S. Treasury obligations and Federal Agency asset-backed securities with a wide range of maturities. These investments are valued using an evaluated pricing approach that varies by asset class and reflects observable market information such as the most recent exchange price or quoted bid for similar securities. Market-based standard inputs typically include benchmark yields, reported trades, broker/dealer quotes and issuer spreads or the most recent quotes for similar securities which are a Level 2 measure.
(F)Certain commingled equity funds are not included in the fair value hierarchy as they are measured at fair value using the NAV per share (or its equivalent) practical expedient. These funds do not meet the definition of readily determinable fair value due to the frequency of publishing NAV (monthly). The objectives of these funds are mainly tracking the S&P Index or achieving long-term growth through investment in foreign equity securities and the Morgan Stanley Capital International Index.
(G)The unlisted real estate fund invests in office, apartment, industrial and retail space. The fund is valued using the NAV per unit of funds. The investment value of the real estate properties is determined on a quarterly basis by independent market appraisers engaged by the board of directors of the fund. The ability to redeem funds is subject to the availability of cash arising from net investment income, allocations and the sale of investments in the normal course of business. The fund’s NAV is published quarterly. In addition, redemptions require one quarter advance notice prior to redemption and are fulfilled quarterly. The fund, therefore, does not meet the definition of readily determinable fair value. The purpose of the fund is to acquire, own, hold for investment and ultimately dispose of investments in real estate and real estate-related assets with the intention of achieving current income, capital appreciation or both.
(H)Private equity investments primarily include various limited partnerships that invest in either operating companies through acquisitions or developing a portfolio of non-U.S. distressed investments to maximize total return on capital. These investments are valued at NAV (or its equivalent) on a quarterly basis and have significant redemption restrictions preventing redemption until fund liquidation and limited ability to sell these investments. Fund liquidation is not expected to occur for several more years. These investments are not included in the fair value hierarchy in accordance with the guidance on NAV practical expedient.
(I)Excludes net receivables of $10 million and $15 million as of December 31, 2020 and 2019, respectively, which consist of interest, dividends and receivables and payables related to pending securities sales and purchases. In addition, the table excludes cash and foreign currency of $1 million and $5 million as of December 31, 2020 and 2019, respectively.
The following table provides the percentage of fair value of total plan assets for each major category of plan assets held for the qualified pension and OPEB plans as of the measurement date, December 31:
As of December 31,
Investments 2020 2019
Equity Securities 72 % 68 %
Debt Securities 22 26
Other Investments 6 6
Total Percentage 100 % 100 %
PSEG utilizes forecasted returns, risk, and correlation of all asset classes in order to develop an efficient portfolio. PSEG’s latest asset/liability study indicates that a long-term target asset allocation of 59% equities, 18% real assets and 23% fixed income is consistent with the funds’ financial objectives. Certain investments in real assets are made through investing in equity securities and tracked as equities when reporting fair value; however, they are viewed by their asset class, real assets, in our target asset allocation. Derivative financial instruments are used by the plans’ investment managers primarily to adjust the fixed income duration of the portfolio and hedge the currency risk component of foreign investments. The expected long-term rate of
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
return on plan assets was 7.7% for 2020 and will be the same for 2021. This expected return was determined based on the study discussed above, including a premium for active management and considered the plans’ historical annualized rate of return since inception.
Plan Contributions
PSEG does not plan to contribute to its pension and OPEB plans in 2021. IRS minimum funding requirements for pension plans are determined based on the fund’s assets and liabilities at the end of a calendar year for the subsequent calendar year. As a result, the market volatility in 2020 associated with the ongoing coronavirus pandemic is not expected to impact PSEG’s pension contributions in 2021.
Estimated Future Benefit Payments
The following pension benefit and postretirement benefit payments are expected to be paid to plan participants.
Year Pension
Benefits Other Benefits
Millions
2021 $ 389 $ 83
2022 368 84
2023 381 84
2024 392 84
2025 401 83
2026-2030 2,119 388
Total $ 4,050 $ 806
401(k) Plans
PSEG sponsors two 401(k) plans, which are defined contribution retirement plans subject to the Employee Retirement Income Security Act (ERISA). Eligible represented employees of PSEG’s subsidiaries participate in the PSEG Employee Savings Plan (Savings Plan), while eligible non-represented employees of PSEG’s subsidiaries participate in the PSEG Thrift and Tax-Deferred Savings Plan (Thrift Plan). Eligible employees may contribute up to 50% of their annual eligible compensation to these plans, not to exceed the IRS maximums, including any catch-up contributions for those employees age 50 and above. PSEG matches 50% of such employee contributions up to 7% of pay for Savings Plan participants and up to 8% of pay for Thrift Plan participants. The amounts paid for employer matching contributions to the plans for PSEG, PSE&G and PSEG Power are detailed as follows:
Thrift Plan and Savings Plan
Years Ended December 31,
2020 2019 2018
Millions
PSE&G $ 27 $ 25 $ 26
PSEG Power 10 10 10
Other 6 5 5
Total Employer Matching Contributions $ 43 $ 40 $ 41
Servco Pension and OPEB
Servco sponsors a qualified pension plan and OPEB plan covering its employees who meet certain eligibility criteria. Under the OSA, employee benefit costs for these plans are funded by LIPA. See Note 5. Variable Interest Entity. These obligations, as well as the offsetting long-term receivable, are separately presented on the Consolidated Balance Sheet of PSEG.
The following table provides a roll-forward of the changes in Servco’s benefit obligation and the fair value of its plan assets during the years ended December 31, 2020 and 2019. It also provides the funded status of the plans and the amounts recognized and amounts not recognized on the Consolidated Balance Sheets at the end of both years.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Pension Benefits Other Benefits
2020 2019 2020 2019
Millions
Change in Benefit Obligation
Benefit Obligation at Beginning of Year (A) $ 453 $ 321 $ 626 $ 501
Service Cost 33 26 20 16
Interest Cost 14 14 20 22
Actuarial (Gain) Loss (B) 74 96 42 96
Gross Benefits Paid (5) (4) (9) (6)
Plan Amendments - - - (3)
Benefit Obligation at End of Year (A) $ 569 $ 453 $ 699 $ 626
Change in Plan Assets
Fair Value of Assets at Beginning of Year $ 282 $ 212 $ - $ -
Actual Return on Plan Assets 36 46 - -
Employer Contributions 30 28 9 6
Gross Benefits Paid (5) (4) (9) (6)
Fair Value of Assets at End of Year $ 343 $ 282 $ - $ -
Funded Status
Funded Status (Plan Assets less Benefit Obligation) $ (226) $ (171) $ (699) $ (626)
Additional Amounts Recognized in the Consolidated Balance Sheets
Accrued Pension Costs of Servco $ (226) $ (171) N/A N/A
OPEB Costs of Servco N/A N/A (699) (626)
Amounts Recognized (C) $ (226) $ (171) $ (699) $ (626)
(A)Represents projected benefit obligation for pension benefits and the accumulated postretirement benefit obligation for other benefits. The vested benefit obligation is the actuarial present value of the vested benefits to which the employee is currently entitled but based on the employee’s expected date of separation or retirement.
(B)For pension benefits, the net actuarial loss was primarily due to a decrease in the discount rate. For OPEB, the net actuarial loss in 2020 was primarily due to a decrease in the discount rate, partially offset by actuarial gains driven by lower than expected participation experience. The OPEB net actuarial loss in 2019 was primarily due to a decrease in the discount rate.
(C)Amounts equal to the accrued pension and OPEB costs of Servco are offset in Long-Term Receivable of VIE on PSEG’s Consolidated Balance Sheets.
Pension and OPEB costs of Servco are accounted for according to the OSA. Servco recognizes expenses for contributions to its pension plan trusts and for OPEB payments made to retirees. Operating Revenues are recognized for the reimbursement of these costs. The pension-related revenues and costs for 2020, 2019 and 2018 were $30 million, $28 million and $40 million, respectively. Servco has contributed its entire planned contribution amount to its pension plan trusts during 2020. The OPEB-related revenues earned and costs incurred were $9 million, $6 million and $6 million in 2020, 2019 and 2018, respectively. The following assumptions were used to determine the benefit obligations of Servco:
Pension Benefits Other Benefits
2020 2019 2018 2020 2019 2018
Weighted-Average Assumptions Used to Determine Benefit Obligations as of December 31
Discount Rate 2.98 % 3.52 % 4.60 % 3.08 % 3.60 % 4.67 %
Rate of Compensation Increase 3.95 % 3.25 % 3.25 % 3.95 % 3.25 % 3.25 %
Cash Balance Interest Crediting Rate 3.75 % 3.75 % 3.75 % N/A N/A N/A
Assumed Health Care Cost Trend Rates as of December 31
Health Care Costs
Immediate Rate 6.70 % 6.94 % 8.03 %
Ultimate Rate 4.75 % 4.75 % 4.75 %
Year Ultimate Rate Reached 2029 2029 2026
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Plan Assets
All the investments of Servco’s pension plans are held in a trust account by the Trustee and consist of an undivided interest in an investment account of the Servco Master Trust. The investments in the pension are measured at fair value within a hierarchy that prioritizes the inputs to fair value measurements into three levels. See Note 19. Fair Value Measurements for more information on fair value guidance.
The following tables present information about Servco’s investments measured at fair value on a recurring basis as of December 31, 2020 and 2019, including the fair value measurements and the levels of inputs used in determining those fair values.
Recurring Fair Value Measurements as of December 31, 2020
Quoted Market Prices
for Identical Assets Significant Other
Observable Inputs Significant
Unobservable Inputs
Description Total (Level 1) (Level 2) (Level 3)
Millions
Cash Equivalents $ 1 $ 1 $ - $ -
Commingled Equities (A) 259 - 259 -
Commingled Bonds (A) 83 - 83 -
Total $ 343 $ 1 $ 342 $ -
Recurring Fair Value Measurements as of December 31, 2019
Quoted Market Prices
for Identical Assets Significant Other
Observable Inputs Significant
Unobservable Inputs
Description Total (Level 1) (Level 2) (Level 3)
Millions
Commingled Equities (A)
$ 202 $ - $ 202 $ -
Commingled Bonds (A)
80 - 80 -
Total $ 282 $ - $ 282 $ -
(A)Investments in commingled equity and bond funds have a readily determinable fair value as they publish a daily NAV available to investors which is the basis for current transactions and contain certain redemption restrictions requiring advance notice of one to two days for withdrawals (Level 2).
The following table provides the percentage of fair value of total plan assets for each major category of plan assets held for the qualified pension and OPEB plans of Servco as of the measurement date, December 31:
As of December 31,
Investments 2020 2019
Equity Securities 76 % 72 %
Debt Securities 24 28
Total Percentage 100 % 100 %
Servco utilizes forecasted returns, risk, and correlation of all asset classes in order to develop an efficient portfolio. The results from Servco’s latest asset/liability study indicated that a long-term target asset allocation of 60% equities, 15% real assets and 25% fixed income is consistent with the funds’ financial objectives. Certain investments in real assets are made through investing in equity securities and tracked as equities when reporting fair value; however, they are viewed by their asset class, real assets, in our target asset allocation. The expected long-term rate of return on plan assets was 7.6% for 2020 and will be the same for 2021. This expected return was determined based on the study discussed above, including a premium for active management.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Plan Contributions
Servco plans to contribute $37 million into its pension plan during 2021. IRS minimum funding requirements for pension plans are determined based on the fund’s assets and liabilities at the end of a calendar year for the subsequent calendar year. As a result, the market volatility in 2020 associated with the ongoing coronavirus pandemic is not expected to impact Servco’s pension contributions in 2021.
Estimated Future Benefit Payments
The following pension benefit and postretirement benefit payments are expected to be paid to Servco’s plan participants:
Year Pension
Benefits Other Benefits
Millions
2021 $ 8 $ 9
2022 10 11
2023 12 13
2024 15 15
2025 17 17
2026-2030 123 111
Total $ 185 $ 176
Servco 401(k) Plans
Servco sponsors two 401(k) plans, which are defined contribution retirement plans subject to ERISA. Eligible non-represented employees of Servco participate in the Long Island Electric Utility Servco LLC Incentive Thrift Plan I (Thrift Plan I), and eligible represented employees of Servco participate in the Long Island Electric Utility Servco LLC Incentive Thrift Plan II (Thrift Plan II). Participants in the plans may contribute up to 50% of their eligible compensation to these plans, not to exceed the IRS maximums, including any catch-up contributions for those employees age 50 and above. Servco does not provide an employer match or core contribution for employees in Thrift Plan II. For employees in Thrift Plan I, Servco matches 50% of such employee contributions up to 8% of eligible compensation and provides core contributions (based on years of service and age) to employees who do not participate in Servco’s Retirement Income Plan. The amounts expensed by Servco for employer matching contributions for the years ended December 31, 2020, 2019 and 2018 were $9 million, $8 million and $7 million, respectively, and pursuant to the OSA, Servco recognizes Operating Revenues for the reimbursement of these costs.
Note 15. Commitments and Contingent Liabilities
Guaranteed Obligations
PSEG Power’s activities primarily involve the purchase and sale of energy and related products under transportation, physical, financial and forward contracts at fixed and variable prices. These transactions are with numerous counterparties and brokers that may require cash, cash-related instruments or guarantees as a form of collateral.
PSEG Power has unconditionally guaranteed payments to counterparties on behalf of its subsidiaries in commodity-related transactions in order to
•support current exposure, interest and other costs on sums due and payable in the ordinary course of business, and
•obtain credit.
PSEG Power is subject to
•counterparty collateral calls related to commodity contracts of its subsidiaries, and
•certain creditworthiness standards as guarantor under performance guarantees of its subsidiaries.
Under these agreements, guarantees cover lines of credit between entities and are often reciprocal in nature. The exposure between counterparties can move in either direction.
In order for PSEG Power to incur a liability for the face value of the outstanding guarantees,
•its subsidiaries would have to fully utilize the credit granted to them by every counterparty to whom PSEG Power has provided a guarantee, and
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
•the net position of the related contracts would have to be “out-of-the-money” (if the contracts are terminated, PSEG Power would owe money to the counterparties).
PSEG Power believes the probability of this result is unlikely. For this reason, PSEG Power believes that the current exposure at any point in time is a more meaningful representation of the potential liability under these guarantees. Current exposure consists of the net of accounts receivable and accounts payable and the forward value on open positions, less any collateral posted.
Changes in commodity prices can have a material impact on collateral requirements under such contracts, which are posted and received primarily in the form of cash and letters of credit. PSEG Power also routinely enters into futures and options transactions for electricity and natural gas as part of its operations. These futures contracts usually require a cash margin deposit with brokers, which can change based on market movement and in accordance with exchange rules.
In addition to the guarantees discussed above, PSEG Power has also provided payment guarantees to third parties and regulatory authorities on behalf of its affiliated companies. These guarantees support various other non-commodity related obligations.
The following table shows the face value of PSEG Power’s outstanding guarantees, current exposure and margin positions as of December 31, 2020 and 2019.
As of December 31, 2020 As of December 31, 2019
Millions
Face Value of Outstanding Guarantees $ 1,792 $ 1,854
Exposure under Current Guarantees $ 128 $ 171
Letters of Credit Margin Posted $ 128 $ 121
Letters of Credit Margin Received $ 45 $ 29
Cash Deposited and Received
Counterparty Cash Collateral Deposited $ - $ -
Counterparty Cash Collateral Received $ (5) $ (4)
Net Broker Balance Deposited (Received) $ 59 $ 48
Additional Amounts Posted
Other Letters of Credit $ 42 $ 82
As part of determining credit exposure, PSEG Power nets receivables and payables with the corresponding net fair values of energy contracts. See Note 18. Financial Risk Management Activities for further discussion. In accordance with PSEG’s accounting policy, where it is applicable, cash (received)/deposited is allocated against derivative asset and liability positions with the same counterparty on the face of the Consolidated Balance Sheet. The remaining balances of net cash (received)/deposited after allocation are generally included in Accounts Payable and Receivable, respectively.
In addition to amounts for outstanding guarantees, current exposure and margin positions, PSEG and PSEG Power have posted letters of credit to support PSEG Power’s various other non-energy contractual and environmental obligations. See the preceding table.
Environmental Matters
Passaic River
Lower Passaic River Study Area
The U.S. Environmental Protection Agency (EPA) has determined that a 17-mile stretch of the Passaic River (Lower Passaic River Study Area (LPRSA)) in New Jersey is a “Superfund” site under the Federal Comprehensive Environmental Response, Compensation and Liability Act of 1980 (CERCLA). PSE&G and certain of its predecessors conducted operations at properties in this area, including at one site that was transferred to PSEG Power.
Certain Potentially Responsible Parties (PRPs), including PSE&G and PSEG Power, formed a Cooperating Parties Group (CPG) and agreed to conduct a Remedial Investigation and Feasibility Study of the LPRSA. The CPG allocated, on an interim basis, the associated costs among its members. The interim allocation is subject to change. In June 2019, the EPA conditionally
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
approved the CPG’s Remedial Investigation. In December 2020, the EPA conditionally approved the CPG’s Feasibility Study, which evaluated various adaptive management scenarios for the remediation of only the upper 9 miles of the LPRSA. The EPA’s selection of its preferred adaptive management scenario will be subject to public review and comment prior to the EPA’s announcement of a final selection, which is expected in 2021.
Separately, the EPA has released a Record of Decision (ROD) for the LPRSA’s lower 8.3 miles that requires the removal of sediments at an estimated cost of $2.3 billion (ROD Remedy). An EPA-commenced process to allocate the associated costs is underway and PSEG cannot predict the outcome. The allocation does not address certain costs incurred by the EPA for which they may be entitled to reimbursement and which may be material. Occidental Chemical Corporation, one of the PRPs, has commenced the design of the ROD Remedy, but declined to participate in the allocation process. Instead, it filed suit against PSE&G and others seeking cost recovery and contribution under CERCLA but has not quantified alleged damages. The litigation is ongoing and PSEG cannot predict the outcome.
Two PRPs, Tierra Solutions, Inc. (Tierra) and Maxus Energy Corporation (Maxus), have filed for Chapter 11 bankruptcy. The trust representing the creditors in this proceeding has filed a complaint asserting claims against Tierra’s and Maxus’ current and former parent entities, among others. Any damages awarded may be used to fund the remediation of the LPRSA.
As of December 31, 2020, PSEG has approximately $65 million accrued for this matter. PSE&G has an Environmental Costs Liability of $52 million and a corresponding Regulatory Asset based on its continued ability to recover such costs in its rates. PSEG Power has an Other Noncurrent Liability of $13 million.
The outcome of this matter is uncertain, and until (i) a final remedy for the entire LPRSA is selected and an agreement is reached by the PRPs to fund it, (ii) PSE&G’s and PSEG Power’s respective shares of the costs are determined, and (iii) PSE&G’s ability to recover the costs in its rates is determined, it is not possible to predict this matter’s ultimate impact on PSEG’s financial statements. It is possible that PSE&G and PSEG Power will record additional costs beyond what they have accrued, and that such costs could be material, but PSEG cannot at the current time estimate the amount or range of any additional costs.
Natural Resource Damage Claims
New Jersey and certain federal regulators have alleged that PSE&G, PSEG Power and 56 other PRPs may be liable for natural resource damages within the LPRSA. In particular, PSE&G, PSEG Power and other PRPs received notice from federal regulators of the regulators’ intent to move forward with a series of studies assessing potential damages to natural resources at the Diamond Alkali Superfund Site, which includes the LPRSA and the Newark Bay Study Area. PSE&G and PSEG Power are unable to estimate their respective portions of any possible loss or range of loss related to this matter.
Newark Bay Study Area
The EPA has established the Newark Bay Study Area, which is an extension of the LPRSA and includes Newark Bay and portions of surrounding waterways. The EPA has notified PSEG and 11 other PRPs of their potential liability. PSE&G and PSEG Power are unable to estimate their respective portions of any loss or possible range of loss related to this matter. In December 2018, PSEG Power completed the sale of the site of the Hudson electric generating station. PSEG Power contractually transferred all land rights and structures on the Hudson site to a third-party purchaser, along with the assumption of the environmental liabilities for the site.
MGP Remediation Program
PSE&G is working with the New Jersey Department of Environmental Protection (NJDEP) to assess, investigate and remediate environmental conditions at its former MGP sites. To date, 38 sites requiring some level of remedial action have been identified. Based on its current studies, PSE&G has determined that the estimated cost to remediate all MGP sites to completion could range between $320 million and $358 million on an undiscounted basis, including its $52 million share for the Passaic River as discussed above. Since no amount within the range is considered to be most likely, PSE&G has recorded a liability of $320 million as of December 31, 2020. Of this amount, $89 million was recorded in Other Current Liabilities and $231 million was reflected as Environmental Costs in Noncurrent Liabilities. PSE&G has recorded a $320 million Regulatory Asset with respect to these costs. PSE&G periodically updates its studies taking into account any new regulations or new information which could impact future remediation costs and adjusts its recorded liability accordingly. PSE&G completed sampling in the Passaic River to delineate coal tar from certain MGP sites that abut the Passaic River Superfund site. PSEG cannot determine at this time whether this will have an impact on the Passaic River Superfund remedy.
CWA Section 316(b) Rule
The EPA’s CWA Section 316(b) rule establishes requirements for the regulation of cooling water intakes at existing power plants and industrial facilities with a design flow of more than two million gallons of water per day. The EPA requires that National Pollutant Discharge Elimination System permits be renewed every five years and that each state Permitting Director
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
manage renewal permits for its respective power generation facilities on a case by case basis. The NJDEP manages the permits under the New Jersey Pollutant Discharge Elimination System (NJPDES) program. Connecticut and New York also have permits to manage their respective pollutant discharge elimination system programs.
In June 2016, the NJDEP issued a final NJPDES permit for Salem. In July 2016, the Delaware Riverkeeper Network (Riverkeeper) filed an administrative hearing request challenging certain conditions of the permit, including the NJDEP’s application of the 316(b) rule. If the Riverkeeper’s challenge is successful, PSEG Power may be required to incur additional costs to comply with the CWA. Potential cooling water and/or service water system modification costs could be material and could adversely impact the economic competitiveness of this facility. The NJDEP had granted the hearing request but no hearing date has been established.
Jersey City, New Jersey Subsurface Feeder Cable Matter
In October 2016, a discharge of dielectric fluid from subsurface feeder cables located in the Hudson River near Jersey City, New Jersey, was identified and reported to the NJDEP. The feeder cables are located within a subsurface easement granted to PSE&G by the property owners, Newport Associates Development Company (NADC) and Newport Associates Phase I Developer Limited Partnership. The feeder cables are subject to agreements between PSE&G and Consolidated Edison Company of New York, Inc. (Con Edison) and are jointly owned by PSE&G and Con Edison. The impacted cable was repaired in September 2017. A federal response was initially led by the U.S. Coast Guard. The U.S. Coast Guard transitioned control of the federal response to the EPA, and the EPA ended the federal response to the matter in 2018. The investigation of small amounts of residual dielectric fluid believed to be contained with the marina sediment is ongoing as part of the NJDEP site remediation program. In August 2020, PSE&G finalized a settlement with the federal government regarding the reimbursement of costs associated with the federal response to this matter and payment of civil penalties of an immaterial amount.
A lawsuit in federal court is pending to determine ultimate responsibility for the costs to address the leak among PSE&G, Con Edison and NADC. In addition, Con Edison filed counter claims against PSE&G and NADC, including seeking injunctive relief and damages. Based on the information currently available and depending on the outcome of the federal court action, PSE&G’s portion of the costs to address the leak may be material; however, PSE&G anticipates that it will recover its costs, other than civil penalties, through regulatory proceedings.
BGS, BGSS and ZECs
Each year, PSE&G obtains its electric supply requirements through annual New Jersey BGS auctions for two categories of customers that choose not to purchase electric supply from third-party suppliers. The first category, which represents about 80% of PSE&G’s load requirement, is residential and smaller commercial and industrial customers (BGS-Residential Small Commercial Pricing (RSCP)). The second category is larger customers that exceed a BPU-established load (kW) threshold (BGS-Commercial and Industrial Energy Pricing (CIEP)). Pursuant to applicable BPU rules, PSE&G enters into the Supplier Master Agreements with the winners of these RSCP and CIEP BGS auctions to purchase BGS for PSE&G’s load requirements. The winners of the RSCP and CIEP auctions have been responsible for fulfilling all the requirements of a PJM load-serving entity including the provision of capacity, energy, ancillary services, transmission and any other services required by PJM. BGS suppliers assume all volume risk and customer migration risk and must satisfy New Jersey’s renewable portfolio standards. Beginning with the 2021 BGS auction, transmission will become the responsibility of the New Jersey EDCs, and will no longer be a component of the BGS auction product for either the RSCP or CIEP auctions. BGS suppliers serving load from the 2018, 2019 and 2020 BGS auctions have the option to transfer the transmission obligation to the New Jersey EDCs as of February 2021. Suppliers that do so will have their total BGS payment from the EDCs reduced to reflect the transfer of the transmission obligation to the EDCs.
The BGS-CIEP auction is for a one-year supply period from June 1 to May 31 with the BGS-CIEP auction price measured in dollars per MW-day for capacity. The final price for the BGS-CIEP auction year commencing June 1, 2021 is $351.06 per MW-day, replacing the BGS-CIEP auction year price ending May 31, 2021 of $359.98 per MW-day. Energy for BGS-CIEP is priced at hourly PJM locational marginal prices for the contract period.
PSE&G contracts for its anticipated BGS-RSCP load on a three-year rolling basis, whereby each year one-third of the load is procured for a three-year period. The contract prices in dollars per MWh for the BGS-RSCP supply, as well as the approximate load, are as follows:
Auction Year
2018 2019 2020 2021
36-Month Terms Ending May 2021 May 2022 May 2023 May 2024 (A)
Load (MW) 2,900 2,800 2,800 2,900
$ per MWh $91.77 $98.04 $102.16 $64.80
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(A)Prices set in the 2021 BGS auction will become effective on June 1, 2021 when the 2018 BGS auction agreements expire.
PSE&G has a full-requirements contract with PSEG Power to meet the gas supply requirements of PSE&G’s gas customers. PSEG Power has entered into hedges for a portion of these anticipated BGSS obligations, as permitted by the BPU. The BPU permits PSE&G to recover the cost of gas hedging up to 115 billion cubic feet or 80% of its residential gas supply annual requirements through the BGSS tariff. Current plans call for PSEG Power to hedge on behalf of PSE&G approximately 70 billion cubic feet or 50% of its residential gas supply annual requirements. For additional information, see Note 26. Related-Party Transactions.
Pursuant to a process established by the BPU, New Jersey EDCs, including PSE&G, are required to purchase ZECs from eligible nuclear plants selected by the BPU. In April 2019, PSEG Power’s Salem 1, Salem 2 and Hope Creek nuclear plants were selected to receive ZEC revenue for approximately three years, through May 2022. PSE&G has implemented a tariff to collect a non-bypassable distribution charge in the amount of $0.004 per KWh from its retail distribution customers to be used to purchase the ZECs from these plants. PSE&G will purchase the ZECs on a monthly basis with payment to be made annually following completion of each energy year. The legislation also requires nuclear plants to reapply for any subsequent three-year periods and allows the BPU to adjust prospective ZEC payments.
Minimum Fuel Purchase Requirements
PSEG Power’s nuclear fuel strategy is to maintain certain levels of uranium and to make periodic purchases to support such levels. As such, the commitments referred to in the following table may include estimated quantities to be purchased that deviate from contractual nominal quantities. PSEG Power’s nuclear fuel commitments cover approximately 100% of its estimated uranium, enrichment and fabrication requirements through 2021 and a significant portion through 2022 at Salem, Hope Creek and Peach Bottom.
PSEG Power has various multi-year contracts for natural gas and firm transportation and storage capacity for natural gas that are primarily used to meet its obligations to PSE&G. When there is excess delivery capacity available beyond the needs of PSE&G’s customers, PSEG Power can use the gas to supply its fossil generating stations in New Jersey.
As of December 31, 2020, the total minimum purchase requirements included in these commitments were as follows:
Fuel Type PSEG Power’s Share of Commitments through 2025
Millions
Nuclear Fuel
Uranium $ 193
Enrichment $ 346
Fabrication $ 174
Natural Gas $ 1,256
Pending FERC Matters
PSE&G has received requests for information and a Notice of Investigation from FERC’s Office of Enforcement concerning a transmission project. PSE&G retained outside counsel to assist with an internal investigation. PSE&G is fully cooperating with FERC’s requests for information and the investigation. It is not possible at this time to predict the outcome of this matter.
Pending Tropical Storm Matter
Following the effects of Tropical Storm Isaias, the New York Attorney General initiated an inquiry into PSEG LI’s preparation and response to the storm. In addition, the Department of Public Service (DPS) within the New York State Public Service Commission launched an investigation of state electric service providers, including PSEG LI, and other state telephone, cable and internet providers into their preparation and restoration efforts following Tropical Storm Isaias. Although the inquiry by the New York Attorney General remains pending, the DPS issued an interim storm investigation report. With respect to PSEG LI, the DPS’ report found that PSEG LI violated its Emergency Response Plan and DPS Regulations, and recommended that LIPA consider taking various actions, including terminating or renegotiating the Amended and Restated OSA. LIPA also initiated its own review of PSEG LI’s performance and issued a report with recommendations for improvements to PSEG LI’s structure and processes, including a timeline for implementing those recommendations. That report also recommended that LIPA either renegotiate or terminate the OSA.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PSEG LI agreed with LIPA that it would fund approximately $6.5 million in claims by customers for food and medication spoilage costs incurred as a result of being without electric service during the storm.
In December 2020, LIPA filed a complaint against PSEG LI in New York State court alleging multiple breaches of the OSA in connection with PSEG LI’s preparation for and response to Tropical Storm Isaias seeking specific performance and $70 million in damages. Pursuant to recommendations by the New York State Department of Public Service, LIPA has initiated a series of actions to allow its board to determine whether to seek to terminate the OSA or instead continue with PSEG LI as its Service Provider.
PSEG LI is fully cooperating with the inquiries by the New York Attorney General and the DPS, and we cannot predict their outcome. PSEG LI also continues to work closely with LIPA to address the recommendations in LIPA’s report. PSEG LI intends to vigorously defend itself with regard to the allegations in LIPA’s complaint alleging breaches of the OSA; however a decision in this proceeding requiring specific performance or the payment of damages by PSEG LI or resulting in the termination of the OSA could have a material adverse effect on PSEG’s results of operations and financial condition.
Pending BPU Audit of PSE&G
In September 2020, the BPU ordered the commencement of a comprehensive affiliate and management audit of PSE&G. Phase 1 of the planned audit will review affiliate relations and cost allocation between PSE&G and its affiliates, including an analysis of the relationship between PSE&G and PSEG Energy Resources & Trade, LLC, a wholly owned subsidiary of PSEG Power over the past ten years, and between PSE&G and PSEG LI. Phase 2 will be a comprehensive management audit, which will address, among other things, executive management, corporate governance, system operations, human resources, cyber security, compliance with customer protection requirements and customer safety. It is not possible at this time to predict the outcome of this matter.
Litigation
Sewaren 7 Construction
In June 2018, a complaint was filed in federal court in Newark, New Jersey against PSEG Fossil LLC, a wholly owned subsidiary of PSEG Power, regarding an ongoing dispute with Durr Mechanical Construction, Inc. (Durr), a contractor on the Sewaren 7 project. Among other things, Durr seeks damages of $93 million and alleges that PSEG Power withheld money owed to Durr and that PSEG Power’s intentional conduct led to the inability of Durr to obtain prospective contracts. PSEG Power intends to vigorously defend against these allegations. In January 2021, the court partially granted PSEG Power’s motion to dismiss certain claims, reducing the amount claimed to $68 million. In December 2018, Durr filed for Chapter 11 bankruptcy in the federal court in the Southern District of New York (SDNY). The SDNY bankruptcy court has allowed the New Jersey litigation to proceed. PSEG Power has accrued an amount related to outstanding invoices which does not reflect an assessment of claims and potential counterclaims in this matter. Due to its preliminary nature, PSEG Power cannot predict the outcome of this matter.
Other Litigation and Legal Proceedings
PSEG and its subsidiaries are party to various lawsuits in the ordinary course of business. In view of the inherent difficulty in predicting the outcome of such matters, PSEG, PSE&G and PSEG Power generally cannot predict the eventual outcome of the pending matters, the timing of the ultimate resolution of these matters, or the eventual loss, fines or penalties related to each pending matter.
In accordance with applicable accounting guidance, a liability is accrued when those matters present loss contingencies that are both probable and reasonably estimable. In such cases, there may be an exposure to loss in excess of any amounts accrued. PSEG will continue to monitor the matter for further developments that could affect the amount of the accrued liability that has been previously established.
Based on current knowledge, management does not believe that loss contingencies arising from pending matters, other than the matters described herein, could have a material adverse effect on PSEG’s, PSE&G’s or PSEG Power’s consolidated financial position or liquidity. However, in light of the inherent uncertainties involved in these matters, some of which are beyond PSEG’s control, and the large or indeterminate damages sought in some of these matters, an adverse outcome in one or more of these matters could be material to PSEG’s, PSE&G’s or PSEG Power’s results of operations or liquidity for any particular reporting period.
Ongoing Coronavirus Pandemic
PSE&G, PSEG Power and PSEG LI are providing essential services during this national emergency related to the ongoing coronavirus (COVID-19) pandemic. The ongoing coronavirus pandemic has not had a material impact on our results of operations, financial condition or cash flows for the year ended December 31, 2020. However, the potential future impact of the pandemic and the associated economic impacts, which could extend beyond the duration of the pandemic, could have risks that
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
drive certain accounting considerations. The ultimate impact of the ongoing coronavirus pandemic is highly uncertain and cannot be predicted at this time.
Nuclear Insurance Coverages and Assessments
PSEG Power is a member of the joint underwriting association, American Nuclear Insurers (ANI), which provides nuclear liability insurance coverage at the Salem and Hope Creek site and the Peach Bottom site. The ANI policies are designed to satisfy the financial protection requirements outlined in the Price-Anderson Act, which sets the limit of liability for claims that could arise from an incident involving any licensed nuclear facility in the United States. The limit of liability per incident per site is composed of primary and excess layers. As of December 31, 2020, nuclear sites were required to purchase $450 million of primary liability coverage for each site (through ANI). The primary layer is supplemented by an excess layer, which is an industry self-insurance pool. In the event a nuclear site, which is part of the industry self-insurance pool, has a claim that exceeds the primary layer, each licensee would be assessed a prorated share of the excess layer. The excess layer limit is $13.3 billion. PSEG Power’s maximum aggregate assessment per incident is $433 million (based on PSEG Power’s ownership interests in Salem, Hope Creek and Peach Bottom) and its maximum aggregate annual assessment per incident is $65 million. If the damages exceed the limit of liability, Congress could impose further revenue-raising measures on the nuclear industry to pay claims. Further, a decision by the U.S. Supreme Court, not involving PSEG Power, held that the Price-Anderson Act did not preclude punitive damage awards based on state law claims.
PSEG Power is also a member of an industry mutual insurance company, Nuclear Electric Insurance Limited (NEIL), which provides the property, decontamination and decommissioning liability insurance at the Salem and Hope Creek site and the Peach Bottom site. NEIL also provides replacement power coverage through its accidental outage policy. NEIL policies may make retrospective premium assessments in the case of adverse loss experience. The current maximum aggregate annual retrospective premium obligation for PSEG Power is approximately $49 million. NEIL requires its members to maintain an investment grade credit rating or to ensure collectability of their annual retrospective premium obligation by providing a financial guarantee, letter of credit, deposit premium, or some other means of assurance. Certain provisions in the NEIL policies provide that the insurer may suspend coverage with respect to all nuclear units on a site without notice if the NRC suspends or revokes the operating license for any unit on that site, issues a shutdown order with respect to such unit or issues a confirmatory order keeping such unit down.
The ANI and NEIL policies all include coverage for claims arising out of acts of terrorism. However, NEIL policies are subject to an industry aggregate limit of $3.2 billion plus such additional amounts as NEIL recovers for such losses from reinsurance, indemnity and any other source applicable to such losses.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 16. Debt and Credit Facilities
Long-Term Debt
As of December 31,
Maturity 2020 2019
Millions
PSEG
Term Loan:
Variable Rate 2020 $ - $ 700
Total Term Loan - 700
Senior Notes:
2.00% 2021 300 300
2.65% 2022 700 700
2.88% 2024 750 750
0.80% 2025 550 -
1.60% 2030 550 -
8.63% (A) 2031 96 -
Total Senior Notes 2,946 1,750
Principal Amount Outstanding 2,946 2,450
Amounts Due Within One Year (300) (700)
Net Unamortized Discount and Debt Issuance Costs (17) (9)
Total Long-Term Debt of PSEG $ 2,629 $ 1,741
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
As of December 31,
Maturity 2020 2019
Millions
PSE&G
First and Refunding Mortgage Bonds (B):
9.25% 2021 $ 134 $ 134
8.00% 2037 7 7
5.00% 2037 8 8
Total First and Refunding Mortgage Bonds 149 149
Medium-Term Notes (B):
3.50% 2020 - 250
7.04% 2020 - 9
1.90% 2021 300 300
2.38% 2023 500 500
3.25% 2023 325 325
3.75% 2024 250 250
3.15% 2024 250 250
3.05% 2024 250 250
3.00% 2025 350 350
2.25% 2026 425 425
3.00% 2027 425 425
3.70% 2028 375 375
3.65% 2028 325 325
3.20% 2029 375 375
2.45% 2030 300 -
5.25% 2035 250 250
5.70% 2036 250 250
5.80% 2037 350 350
5.38% 2039 250 250
5.50% 2040 300 300
3.95% 2042 450 450
3.65% 2042 350 350
3.80% 2043 400 400
4.00% 2044 250 250
4.05% 2045 250 250
4.15% 2045 250 250
3.80% 2046 550 550
3.60% 2047 350 350
4.05% 2048 325 325
3.85% 2049 375 375
3.20% 2049 400 400
3.15% 2050 300 -
2.70% 2050 375 -
2.05% 2050 375 -
Total MTNs 10,850 9,759
Principal Amount Outstanding 10,999 9,908
Amounts Due Within One Year (434) (259)
Net Unamortized Discount and Selling Expense (90) (81)
Total Long-Term Debt of PSE&G $ 10,475 $ 9,568
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
As of December 31,
Maturity 2020 2019
Millions
PSEG Power
Senior Notes:
5.13% 2020 $ - $ 406
3.00% 2021 700 700
4.15% 2021 250 250
3.85% 2023 700 700
4.30% 2023 250 250
8.63% (A) 2031 404 500
Total Senior Notes 2,304 2,806
Pollution Control Notes:
Floating Rate (C) 2022 44 44
Total Pollution Control Notes 44 44
Principal Amount Outstanding 2,348 2,850
Amounts Due Within One Year (950) (406)
Net Unamortized Discount and Debt Issuance Costs (6) (10)
Total Long-Term Debt of PSEG Power $ 1,392 $ 2,434
(A)In December 2020, PSEG issued $96 million principal amount of 8.63% Senior Notes due 2031 to holders of a like principal amount of 8.63% Senior Notes due 2031 originally issued by PSEG Power who validly tendered their notes pursuant to an offer to exchange. Upon consummation of the offer to exchange, the PSEG Power notes accepted in the exchange were cancelled. The transaction resulted in a non-cash financing activity for both PSEG and PSEG Power.
(B)Secured by essentially all property of PSE&G pursuant to its First and Refunding Mortgage.
(C)The Pennsylvania Economic Development Financing Authority (PEDFA) bond that is serviced and secured by PSEG Power Pollution Control Notes is a variable rate bond that is in weekly reset mode.
Long-Term Debt Maturities
The aggregate principal amounts of maturities for each of the five years following December 31, 2020 are as follows:
Year PSEG PSE&G PSEG Power Total
2021 $ 300 $ 434 $ 950 $ 1,684
2022 700 - 44 744
2023 - 825 950 1,775
2024 750 750 - 1,500
2025 550 350 - 900
Thereafter 646 8,640 404 9,690
Total $ 2,946 $ 10,999 $ 2,348 $ 16,293
Long-Term Debt Financing Transactions
During 2020, PSEG and its subsidiaries had the following Long-Term Debt issuances, maturities and redemptions:
PSEG
•issued $550 million of 0.80% Senior Notes due August 2025,
•issued $550 million of 1.60% Senior Notes due August 2030,
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
•issued $96 million of 8.63% Senior Notes due April 2031 in exchange for a like amount of 8.63% Senior Notes due April 2031 originally issued by PSEG Power, and
•retired a $700 million Term Loan at maturity.
PSE&G
•issued $300 million of 2.45% Secured Medium-Term Notes, Series N, due January 2030,
•issued $300 million of 3.15% Secured Medium-Term Notes, Series N, due January 2050,
•issued $375 million of 2.70% Secured Medium-Term Notes, Series N, due May 2050,
•issued $375 million of 2.05% Secured Medium-Term Notes, Series N, due August 2050,
•retired $250 million of 3.50% Medium-Term Notes, Series G, at maturity, and
•retired $9 million of 7.04% Medium-Term Notes, Series A, at maturity.
PSEG Power
•retired $406 million of 5.13% Senior Notes at maturity, and
•cancelled $96 million of 8.63% Senior Notes that were exchanged for a like amount of 8.63% Senior Notes due April 2031 issued by PSEG.
Debt Covenants
PSEG Power’s existing credit agreements and senior notes contain covenants restricting the ability of PSEG Power and its subsidiaries that guarantee its indebtedness from consummating certain mergers, consolidations or asset sales. The disposal of PSEG Power’s non-nuclear generating fleet could, depending on the structure of such transaction, among other factors, trigger a default under one or more of these provisions. For these reasons, or for other reasons, PSEG Power may decide, or be required, to seek amendments or waivers under its credit agreements and may redeem its outstanding senior notes, at a price equal to the principal amount thereof plus a make-whole premium. Whether such amendments, waivers or redemptions will be required will depend on a number of factors, including the structure of any transaction resulting from the strategic review, and any actual redemption price would depend on the applicable treasury rate in effect at such time. It is likewise possible that the ultimate outcome of the process may result in a transaction, or may result in no transaction at all, where the PSEG Power notes are not redeemed. If PSEG Power is required to redeem its senior notes, the cost of such redemption would be material.
Short-Term Liquidity
PSEG meets its short-term liquidity requirements, as well as those of PSEG Power, primarily through the issuance of commercial paper and, from time to time, short-term loans. PSE&G maintains its own separate commercial paper program to meet its short-term liquidity requirements. Each commercial paper program is fully back-stopped by its own separate credit facilities.
The commitments under the $4.2 billion credit facilities are provided by a diverse bank group. As of December 31, 2020, the total available credit capacity was $3.3 billion.
As of December 31, 2020, no single institution represented more than 9% of the total commitments in the credit facilities.
As of December 31, 2020, the total credit capacity was in excess of the anticipated maximum liquidity requirements over PSEG’s 12-month planning horizon, including access to capital to meet redemptions.
Each of the credit facilities is restricted as to availability and use to the specific companies as listed in the following table; however, if necessary, the PSEG facilities can also be used to support our subsidiaries’ liquidity needs.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The total credit facilities and available liquidity as of December 31, 2020 were as follows:
As of December 31, 2020
Company/Facility Total
Facility Usage (D) Available
Liquidity Expiration
Date Primary Purpose
Millions
PSEG
5-year Credit Facilities (A) $ 1,500 $ 665 $ 835 Mar 2024 Commercial Paper Support/Funding/Letters of Credit
Total PSEG $ 1,500 $ 665 $ 835
PSE&G
5-year Credit Facility (B) $ 600 $ 117 $ 483 Mar 2024 Commercial Paper Support/Funding/Letters of Credit
Total PSE&G $ 600 $ 117 $ 483
PSEG Power
3-year Letter of Credit Facility $ 100 $ 48 $ 52 Sept 2021 Letters of Credit
3-year Letter of Credit Facility 100 81 19 Sept 2022 Letters of Credit
5-year Credit Facilities (C) 1,900 39 1,861 Mar 2024 Funding/Letters of Credit
Total PSEG Power $ 2,100 $ 168 $ 1,932
Total $ 4,200 $ 950 $ 3,250
(A)PSEG facilities will be reduced by $9 million in March 2022.
(B)PSE&G facility will be reduced by $4 million in March 2022.
(C)PSEG Power facilities will be reduced by $12 million in March 2022.
(D)The primary use of PSEG’s and PSE&G’s credit facilities is to support their respective Commercial Paper Programs, under which as of December 31, 2020, PSEG had $663 million outstanding at a weighted average interest rate of 0.33%. PSE&G had $100 million outstanding at a weighted average interest rate of 0.28% under its Commercial Paper Program as of December 31, 2020.
Except as otherwise noted in the table above, in March 2020, PSEG, PSE&G and PSEG Power and their respective lenders agreed to extend the expiration dates on their credit agreements from March 2023 to March 2024.
Short-Term Loans
PSEG
In March 2020, PSEG entered into a $300 million, 364-day variable rate term loan agreement, which was prepaid in January 2021. In April 2020, PSEG entered into two 364-day variable rate term loan agreements for $200 million and $300 million which were prepaid in August 2020.
Fair Value of Debt
The estimated fair values, carrying amounts and methods used to determine fair value of long-term debt as of December 31, 2020 and 2019 are included in the following table and accompanying notes as of December 31, 2020 and 2019. See Note 19. Fair Value Measurements for more information on fair value guidance and the hierarchy that prioritizes the inputs to fair value measurements into three levels.
December 31, 2020 December 31, 2019
Carrying
Amount Fair
Value Carrying
Amount Fair
Value
Millions
Long-Term Debt:
PSEG (A) (B) $ 2,929 $ 3,092 $ 2,441 $ 2,479
PSE&G (B) 10,909 13,372 9,827 11,107
PSEG Power (B) 2,342 2,679 2,840 3,137
Total Long-Term Debt $ 16,180 $ 19,143 $ 15,108 $ 16,723
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(A)Includes a floating-rate term loan of $700 million at PSEG as of December 31, 2019. The fair value of the term loan debt (Level 2 measurement) approximates the carrying value because the interest payments are based on LIBOR rates that are reset monthly and the debt is redeemable at face value by PSEG at any time.
(B)Given that these bonds do not trade actively, the fair value amounts of taxable debt securities (primarily Level 2 measurements) are generally determined by a valuation model that is based on a conventional discounted cash flow methodology. The fair value amounts above do not represent the price at which the outstanding debt may be called for redemption by each issuer under their respective debt agreements.
Note 17. Schedule of Consolidated Capital Stock
As of December 31,
Outstanding Shares Book Value
2020 2019 2020 2019
Millions
PSEG Common Stock (no par value) (A)
Authorized 1,000 shares
504 504 $ 4,170 $ 4,172
(A)PSEG did not issue any new shares under the Dividend Reinvestment and Stock Purchase Plan or the Employee Stock Purchase Plan (ESPP) in 2020 or 2019.
As of December 31, 2020, PSE&G had an aggregate of 7.5 million shares of $100 par value and 10 million shares of $25 par value Cumulative Preferred Stock, which were authorized and unissued and which, upon issuance, may or may not provide for mandatory sinking fund redemption.
Note 18. Financial Risk Management Activities
Derivative accounting guidance requires that a derivative instrument be recognized as either an asset or a liability at fair value, with changes in fair value of the derivative recognized in earnings each period. Other accounting treatments are available through special election and designation provided that the derivative instrument meets specific, restrictive criteria, both at the time of designation and on an ongoing basis. These alternative permissible treatments include NPNS, cash flow hedge and fair value hedge accounting. PSEG, PSEG Power and PSE&G have applied the NPNS scope exception to certain derivative contracts for the forward sale of generation, power procurement agreements and fuel agreements. PSEG uses interest rate swaps and other derivatives, which are designated and qualifying as cash flow or fair value hedges. PSEG Power enters into additional contracts that are derivatives, but are not designated as either cash flow hedges or fair value hedges. These transactions are economic hedges and are recorded at fair market value with changes recognized in earnings.
Commodity Prices
Within PSEG and its affiliate companies, PSEG Power has the most exposure to commodity price risk. PSEG Power is exposed to commodity price risk primarily relating to changes in the market price of electricity, fossil fuels and other commodities. Fluctuations in market prices result from changes in supply and demand, fuel costs, market conditions, weather, state and federal regulatory policies, environmental policies, transmission availability and other factors. PSEG Power uses a variety of derivative and non-derivative instruments, such as financial options, futures, swaps, fuel purchases and forward purchases and sales of electricity, to manage the exposure to fluctuations in commodity prices and optimize the value of PSEG Power’s expected generation. PSEG Power also uses derivatives to hedge a portion of its anticipated BGSS obligations with PSE&G. For additional information see Note 15. Commitments and Contingent Liabilities. Changes in the fair market value of these derivative contracts are recorded in earnings.
Interest Rates
PSEG, PSEG Power and PSE&G are subject to the risk of fluctuating interest rates in the normal course of business. Exposure to this risk is managed by targeting a balanced debt maturity profile which limits refinancing in any given period or interest rate environment. In addition, they have used a mix of fixed and floating rate debt and interest rate swaps.
Cash Flow Hedges
PSEG uses interest rate swaps and other derivatives, which are designated and effective as cash flow hedges, to manage its exposure to the variability of cash flows, primarily related to variable-rate debt instruments. There were no outstanding interest rate hedges as of December 31, 2020. As of December 31, 2019, PSEG had interest rate hedges outstanding totaling $700
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
million. These hedges converted PSEG’s $700 million variable-rate term loan due November 2020 into a fixed-rate loan. As of December 31, 2019, the fair value of these hedges was $(5) million.
The Accumulated Other Comprehensive Income (Loss) (after tax) related to outstanding and terminated interest rate derivatives designated as cash flow hedges was $(9) million and $(15) million as of December 31, 2020 and December 31, 2019, respectively. The after-tax unrealized losses on these hedges expected to be reclassified to earnings during the next 12 months are $(3) million.
Fair Values of Derivative Instruments
The following are the fair values of derivative instruments on the Consolidated Balance Sheets. The following tables also include disclosures for offsetting derivative assets and liabilities which are subject to a master netting or similar agreement. In general, the terms of the agreements provide that in the event of an early termination the counterparties have the right to offset amounts owed or owing under that and any other agreement with the same counterparty. Accordingly, and in accordance with PSEG’s accounting policy, these positions are offset on the Consolidated Balance Sheets of PSEG Power and PSEG. For additional information see Note 19. Fair Value Measurements. The following tabular disclosure does not include the offsetting of trade receivables and payables.
As of December 31, 2020
PSEG Power (A) Consolidated
Not Designated
Balance Sheet Location Energy-
Related
Contracts Netting
(B) Total
PSEG Power Total
Derivatives
Millions
Derivative Contracts
Current Assets $ 464 $ (404) $ 60 $ 60
Noncurrent Assets 93 (84) 9 9
Total Mark-to-Market Derivative Assets $ 557 $ (488) $ 69 $ 69
Derivative Contracts
Current Liabilities $ (412) $ 391 $ (21) $ (21)
Noncurrent Liabilities (109) 105 (4) (4)
Total Mark-to-Market Derivative (Liabilities) $ (521) $ 496 $ (25) $ (25)
Total Net Mark-to-Market Derivative Assets (Liabilities) $ 36 $ 8 $ 44 $ 44
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
As of December 31, 2019
PSEG Power (A) PSEG (A) Consolidated
Not Designated Cash Flow
Hedges
Balance Sheet Location Energy-
Related
Contracts Netting
(B) Total
PSEG Power Interest
Rate
Swaps Total
Derivatives
Millions
Derivative Contracts
Current Assets $ 636 $ (523) $ 113 $ - $ 113
Noncurrent Assets 163 (139) 24 - 24
Total Mark-to-Market Derivative Assets $ 799 $ (662) $ 137 $ - $ 137
Derivative Contracts
Current Liabilities $ (553) $ 522 $ (31) $ (5) $ (36)
Noncurrent Liabilities (139) 138 (1) - (1)
Total Mark-to-Market Derivative (Liabilities) $ (692) $ 660 $ (32) $ (5) $ (37)
Total Net Mark-to-Market Derivative Assets (Liabilities) $ 107 $ (2) $ 105 $ (5) $ 100
(A) Substantially all of PSEG Power’s and PSEG’s derivative instruments are contracts subject to master netting agreements. Contracts not subject to master netting or similar agreements are immaterial and did not have any collateral posted or received as of December 31, 2020 and 2019.
(B) Represents the netting of fair value balances with the same counterparty (where the right of offset exists) and the application of cash collateral. All cash collateral (received) posted that has been allocated to derivative positions, where the right of offset exists, has been offset on the Consolidated Balance Sheets. As of December 31, 2020 and 2019, PSEG Power had net cash collateral payments to counterparties of $54 million and $44 million, respectively. Of these net cash collateral (receipts) payments, $8 million as of December 31, 2020 and $(2) million as of December 31, 2019 were netted against the corresponding net derivative contract positions. Of the $8 million as of December 31, 2020, $(13) million was netted against current assets, and $21 million was netted against noncurrent liabilities. Of the $(2) million as of December 31, 2019, $(1) million was netted against current assets and $(1) million was netted against noncurrent assets.
Certain of PSEG Power’s derivative instruments contain provisions that require PSEG Power to post collateral. This collateral may be posted in the form of cash or credit support with thresholds contingent upon PSEG Power’s credit rating from each of the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. These credit risk-related contingent features stipulate that if PSEG Power were to be downgraded to a below investment grade rating by S&P or Moody’s, it would be required to provide additional collateral. A below investment grade credit rating for PSEG Power would represent a three level downgrade from its current S&P or Moody’s ratings. This incremental collateral requirement can offset collateral requirements related to other derivative instruments that are assets with the same counterparty, where the contractual right of offset exists under applicable master agreements. PSEG Power also enters into commodity transactions on the New York Mercantile Exchange (NYMEX) and Intercontinental Exchange (ICE). The NYMEX and ICE clearing houses act as counterparties to each trade. Transactions on the NYMEX and ICE must adhere to comprehensive collateral and margin requirements.
The aggregate fair value of all derivative instruments with credit risk-related contingent features in a liability position that are not fully collateralized (excluding transactions on the NYMEX and ICE that are fully collateralized) was $28 million and $35 million as of December 31, 2020 and 2019, respectively. As of December 31, 2020 and 2019, PSEG Power had the contractual right of offset of $3 million and $2 million, respectively, related to derivative instruments that are assets with the same counterparty under master agreements and net of margin posted. If PSEG Power had been downgraded to a below investment grade rating, it would have had additional collateral obligations of $25 million and $33 million as of December 31, 2020 and 2019, respectively, related to its derivatives, net of the contractual right of offset under master agreements and the application of collateral.
The following shows the effect on the Consolidated Statements of Operations and on Accumulated Other Comprehensive Loss (AOCL) of derivative instruments designated as cash flow hedges for the years ended December 31, 2020, 2019 and 2018.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Amount of Pre-Tax
Gain (Loss)
Recognized in AOCL on Derivatives Location of
Pre-Tax
Gain (Loss)
Reclassified from
AOCL into Income Amount of Pre-Tax
Gain (Loss)
Reclassified from
AOCL into Income
Derivatives in Cash Flow Hedging Relationships Years Ended
December 31, Years Ended
December 31,
2020 2019 2018 2020 2019 2018
Millions Millions
PSEG
Interest Rate Swaps $ (6) $ (23) $ (2) Interest Expense $ (14) $ (4) $ -
Total PSEG $ (6) $ (23) $ (2) $ (14) $ (4) $ -
The effect of interest rate cash flow hedges is recorded in Interest Expense in PSEG’s Consolidated Statement of Operations. For the year ended December 31, 2020, the amount of gain or loss on interest rate hedges reclassified from Accumulated Other Comprehensive Income (Loss) into income was $(10) million and $(3) million after tax as of December 31, 2020 and 2019, respectively and immaterial as of December 31, 2018.
The following reconciles the Accumulated Other Comprehensive Income (Loss) for derivative activity included in the AOCL of PSEG on a pre-tax and after-tax basis.
Accumulated Other Comprehensive Income (Loss) Pre-Tax After-Tax
Millions
Balance as of December 31, 2018 $ (2) $ (1)
Loss Recognized in AOCI (23) (17)
Less: Loss Reclassified into Income 4 3
Balance as of December 31, 2019 $ (21) $ (15)
Loss Recognized in AOCI (6) (4)
Less: Loss Reclassified into Income 14 10
Balance as of December 31, 2020 $ (13) $ (9)
The following shows the effect on the Consolidated Statements of Operations of derivative instruments not designated as hedging instruments or as NPNS for the years ended December 31, 2020, 2019 and 2018. PSEG Power’s derivative contracts reflected in this table include contracts to hedge the purchase and sale of electricity and natural gas, and the purchase of fuel. The table does not include contracts that PSEG Power has designated as NPNS, such as its BGS contracts and certain other energy supply contracts that it has with other utilities and companies with retail load.
Derivatives Not Designated as Hedges Location of Pre-Tax
Gain (Loss)
Recognized in Income
on Derivatives Pre-Tax Gain (Loss)
Recognized in Income
on Derivatives
Years Ended December 31,
2020 2019 2018
Millions
PSEG Power
Energy-Related Contracts Operating Revenues $ 279 $ 560 $ (182)
Energy-Related Contracts Energy Costs (142) (119) (9)
Total PSEG and PSEG Power $ 137 $ 441 $ (191)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following table summarizes the net notional volume purchases/(sales) of open derivative transactions by commodity as of December 31, 2020 and 2019.
Type Notional Total PSEG PSEG Power PSE&G
Millions
As of December 31, 2020
Natural Gas Dekatherm (Dth) 321 - 321 -
Electricity MWh (66) - (66) -
Financial Transmission Rights (FTRs) MWh 20 - 20 -
As of December 31, 2019
Natural Gas Dth 341 - 341 -
Electricity MWh (62) - (62) -
FTRs MWh 13 - 13 -
Interest Rate Swaps U.S. Dollars 700 700 - -
Credit Risk
Credit risk relates to the risk of loss that PSEG Power would incur as a result of non-performance by counterparties pursuant to the terms of their contractual obligations. PSEG has established credit policies that it believes significantly minimize credit risk. These policies include an evaluation of potential counterparties’ financial condition (including credit rating), collateral requirements under certain circumstances and the use of standardized agreements, which allow for the netting of positive and negative exposures associated with a single counterparty. In the event of non-performance or non-payment by a major counterparty, there may be a material adverse impact on PSEG Power’s and PSEG’s financial condition, results of operations or net cash flows.
The following table provides information on PSEG Power’s credit risk from wholesale counterparties, net of collateral, as of December 31, 2020. It further delineates that exposure by the credit rating of the counterparties, which is determined by the lowest rating from S&P, Moody’s or an internal scoring model. In addition, it provides guidance on the concentration of credit risk to individual counterparties and an indication of the quality of PSEG Power’s credit risk by credit rating of the counterparties.
As of December 31, 2020, 88% of the net credit exposure for PSEG Power’s wholesale operations was with investment grade counterparties. Credit exposure is defined as any positive results of netting accounts receivable/accounts payable and the forward value of open positions (which includes all financial instruments including derivatives, NPNS and non-derivatives).
Rating Current
Exposure Securities
held as
Collateral Net
Exposure Number of
Counterparties
>10% Net Exposure of
Counterparties
>10% (A)
Millions Millions
Investment Grade $ 337 $ 39 $ 298 1 $ 169
Non-Investment Grade 40 - 40 1 40
Total $ 377 $ 39 $ 338 2 $ 209
(A)Represents net exposure of $169 million with PSE&G and $40 million with a non-affiliated counterparty.
As of December 31, 2020, collateral held from counterparties where PSEG Power had credit exposure includes $4 million in cash and $35 million in letters of credit.
As of December 31, 2020, PSEG Power had 135 active counterparties.
PSE&G’s supplier master agreements are approved by the BPU and govern the terms of its electric supply procurement contracts. These agreements define a supplier’s performance assurance requirements and allow a supplier to meet its credit requirements with a certain amount of unsecured credit. The amount of unsecured credit is determined based on the supplier’s credit ratings from the major credit rating agencies and the supplier’s tangible net worth. The credit position is based on the initial market price, which is the forward price of energy on the day the procurement transaction is executed, compared to the forward price curve for energy on the valuation day. To the extent that the forward price curve for energy exceeds the initial market price, the supplier is required to post a parental guaranty or other security instrument such as a letter of credit or cash, as collateral to the extent the credit exposure is greater than the supplier’s unsecured credit limit. As of December 31, 2020,
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
primarily all of the posted collateral was in the form of parental guarantees. The unsecured credit used by the suppliers represents PSE&G’s net credit exposure. PSE&G’s BGS suppliers’ credit exposure is calculated each business day. As of December 31, 2020, PSE&G had no net credit exposure with suppliers, including PSEG Power.
PSE&G is permitted to recover its costs of procuring energy through the BPU-approved BGS tariffs. PSE&G’s counterparty credit risk is mitigated by its ability to recover realized energy costs through customer rates.
Note 19. Fair Value Measurements
Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Accounting guidance for fair value measurement emphasizes that fair value is a market-based measurement, not an entity-specific measurement, and establishes a fair value hierarchy that distinguishes between assumptions based on market data obtained from independent sources and those based on an entity’s own assumptions. The hierarchy prioritizes the inputs to fair value measurement into three levels:
Level 1-measurements utilize quoted prices (unadjusted) in active markets for identical assets or liabilities that PSEG, PSE&G and PSEG Power have the ability to access. These consist primarily of listed equity securities and money market mutual funds, as well as natural gas futures contracts executed on NYMEX.
Level 2-measurements include quoted prices for similar assets and liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, and other observable inputs such as interest rates and yield curves that are observable at commonly quoted intervals. These consist primarily of non-exchange traded derivatives such as forward contracts or options and most fixed income securities.
Level 3-measurements use unobservable inputs for assets or liabilities, based on the best information available and might include an entity’s own data and assumptions. In some valuations, the inputs used may fall into different levels of the hierarchy. In these cases, the financial instrument’s level within the fair value hierarchy is based on the lowest level of input that is significant to the fair value measurement. These consist primarily of certain electric load contracts and gas contracts.
Certain derivative transactions may transfer from Level 2 to Level 3 if inputs become unobservable and internal modeling techniques are employed to determine fair value. Conversely, measurements may transfer from Level 3 to Level 2 if the inputs become observable.
The following tables present information about PSEG’s, PSE&G’s and PSEG Power’s respective assets and (liabilities) measured at fair value on a recurring basis as of December 31, 2020 and December 31, 2019, including the fair value measurements and the levels of inputs used in determining those fair values. Amounts shown for PSEG include the amounts shown for PSE&G and PSEG Power.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Recurring Fair Value Measurements as of December 31, 2020
Description Total Netting (D) Quoted Market Prices for Identical Assets
(Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs
(Level 3)
Millions
PSEG
Assets:
Cash Equivalents (A) $ 312 $ - $ 312 $ - $ -
Derivative Contracts:
Energy-Related Contracts (B) $ 69 $ (488) $ 26 $ 519 $ 12
NDT Fund (C)
Equity Securities $ 1,352 $ - $ 1,351 $ 1 $ -
Debt Securities-U.S. Treasury $ 239 $ - $ - $ 239 $ -
Debt Securities-Govt Other $ 342 $ - $ - $ 342 $ -
Debt Securities-Corporate $ 566 $ - $ - $ 566 $ -
Rabbi Trust (C)
Equity Securities $ 31 $ - $ 31 $ - $ -
Debt Securities-U.S. Treasury $ 59 $ - $ - $ 59 $ -
Debt Securities-Govt Other $ 41 $ - $ - $ 41 $ -
Debt Securities-Corporate $ 135 $ - $ - $ 135 $ -
Liabilities:
Derivative Contracts:
Energy-Related Contracts (B) $ (25) $ 496 $ (33) $ (483) $ (5)
PSE&G
Assets:
Cash Equivalents (A) $ 50 $ - $ 50 $ - $ -
Rabbi Trust (C)
Equity Securities $ 6 $ - $ 6 $ - $ -
Debt Securities-U.S. Treasury $ 11 $ - $ - $ 11 $ -
Debt Securities-Govt Other $ 8 $ - $ - $ 8 $ -
Debt Securities-Corporate $ 26 $ - $ - $ 26 $ -
PSEG Power
Assets:
Derivative Contracts:
Energy-Related Contracts (B) $ 69 $ (488) $ 26 $ 519 $ 12
NDT Fund (C)
Equity Securities $ 1,352 $ - $ 1,351 $ 1 $ -
Debt Securities-U.S. Treasury $ 239 $ - $ - $ 239 $ -
Debt Securities-Govt Other $ 342 $ - $ - $ 342 $ -
Debt Securities-Corporate $ 566 $ - $ - $ 566 $ -
Rabbi Trust (C)
Equity Securities $ 8 $ - $ 8 $ - $ -
Debt Securities-U.S. Treasury $ 15 $ - $ - $ 15 $ -
Debt Securities-Govt Other $ 10 $ - $ - $ 10 $ -
Debt Securities-Corporate $ 33 $ - $ - $ 33 $ -
Liabilities:
Derivative Contracts:
Energy-Related Contracts (B) $ (25) $ 496 $ (33) $ (483) $ (5)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Recurring Fair Value Measurements as of December 31, 2019
Description Total Netting (D) Quoted Market Prices for Identical Assets
(Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs
(Level 3)
Millions
PSEG
Assets:
Cash Equivalents (A) $ 50 $ - $ 50 $ - $ -
Derivative Contracts:
Energy-Related Contracts (B) $ 137 $ (662) $ 19 $ 770 $ 10
NDT Fund (C)
Equity Securities $ 1,151 $ - $ 1,150 $ 1 $ -
Debt Securities-U.S. Treasury $ 225 $ - $ - $ 225 $ -
Debt Securities-Govt Other $ 352 $ - $ - $ 352 $ -
Debt Securities-Corporate $ 486 $ - $ - $ 486 $ -
Rabbi Trust (C)
Equity Securities $ 28 $ - $ 28 $ - $ -
Debt Securities-U.S. Treasury $ 57 $ - $ - $ 57 $ -
Debt Securities-Govt Other $ 47 $ - $ - $ 47 $ -
Debt Securities-Corporate $ 114 $ - $ - $ 114 $ -
Liabilities:
Derivative Contracts:
Energy-Related Contracts (B) $ (32) $ 660 $ (43) $ (646) $ (3)
Interest Rate Swaps (E) $ (5) $ - $ - $ (5) $ -
PSE&G
Assets:
Rabbi Trust (C)
Equity Securities $ 5 $ - $ 5 $ - $ -
Debt Securities-U.S. Treasury $ 11 $ - $ - $ 11 $ -
Debt Securities-Govt Other $ 9 $ - $ - $ 9 $ -
Debt Securities-Corporate $ 23 $ - $ - $ 23 $ -
PSEG Power
Assets:
Derivative Contracts:
Energy-Related Contracts (B) $ 137 $ (662) $ 19 $ 770 $ 10
NDT Fund (C)
Equity Securities $ 1,151 $ - $ 1,150 $ 1 $ -
Debt Securities-U.S. Treasury $ 225 $ - $ - $ 225 $ -
Debt Securities-Govt Other $ 352 $ - $ - $ 352 $ -
Debt Securities-Corporate $ 486 $ - $ - $ 486 $ -
Rabbi Trust (C)
Equity Securities $ 8 $ - $ 8 $ - $ -
Debt Securities-U.S. Treasury $ 14 $ - $ - $ 14 $ -
Debt Securities-Govt Other $ 12 $ - $ - $ 12 $ -
Debt Securities-Corporate $ 28 $ - $ - $ 28 $ -
Liabilities:
Derivative Contracts:
Energy-Related Contracts (B) $ (32) $ 660 $ (43) $ (646) $ (3)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(A)Represents money market mutual funds.
(B)Level 1-These contracts represent natural gas futures contracts executed on NYMEX, and are being valued solely on settled pricing inputs which come directly from the exchange.
Level 2-Fair values for energy-related contracts are obtained primarily using a market-based approach. Most derivative contracts (forward purchase or sale contracts and swaps) are valued using settled prices from similar assets and liabilities from an exchange, such as NYMEX, ICE and Nodal Exchange, or auction prices. Prices used in the valuation process are also corroborated independently by management to determine that values are based on actual transaction data or, in the absence of transactions, bid and offers for the day. Examples may include certain exchange and non-exchange traded capacity and electricity contracts and natural gas physical or swap contracts based on market prices, basis adjustments and other premiums where adjustments and premiums are not considered significant to the overall inputs.
Level 3-Unobservable inputs are used for the valuation of certain contracts. See “Additional Information Regarding Level 3 Measurements” below for more information on the utilization of unobservable inputs.
(C)As of December 31, 2020 and 2019, the fair value measurement table excludes foreign currency of $2 million in the NDT Fund. The NDT Fund maintains investments in various equity and fixed income securities. The Rabbi Trust maintains investments in a Russell 3000 index fund and various fixed income securities. These securities are generally valued with prices that are either exchange provided (equity securities) or market transactions for comparable securities and/or broker quotes (fixed income securities).
Level 1-Investments in marketable equity securities within the NDT Fund are primarily investments in common stocks across a broad range of industries and sectors. Most equity securities are priced utilizing the principal market close price or, in some cases, midpoint, bid or ask price. Certain other equity securities in the NDT and Rabbi Trust Funds consist primarily of investments in money market funds which seek a high level of current income as is consistent with the preservation of capital and the maintenance of liquidity. To pursue its goals, the funds normally invest in diversified portfolios of high quality, short-term, dollar-denominated debt securities and government securities. The funds’ net asset value is priced and published daily. The Rabbi Trust’s Russell 3000 index fund is valued based on quoted prices in an active market and can be redeemed daily without restriction.
Level 2-NDT and Rabbi Trust fixed income securities include investment grade corporate bonds, collateralized mortgage obligations, asset-backed securities and certain government and U.S. Treasury obligations or Federal Agency asset-backed securities and municipal bonds with a wide range of maturities. Since many fixed income securities do not trade on a daily basis, they are priced using an evaluated pricing methodology that varies by asset class and reflects observable market information such as the most recent exchange price or quoted bid for similar securities. Market-based standard inputs typically include benchmark yields, reported trades, broker/dealer quotes and issuer spreads. The preferred stocks are not actively traded on a daily basis and therefore, are also priced using an evaluated pricing methodology. Certain short-term investments are valued using observable market prices or market parameters such as time-to-maturity, coupon rate, quality rating and current yield.
(D)Represents the netting of fair value balances with the same counterparty (where the right of offset exists) and the application of collateral. See Note 18. Financial Risk Management Activities for additional detail.
(E)Interest rate swaps are valued using quoted prices on commonly quoted intervals, which are interpolated for periods different than the quoted intervals, as inputs to a market valuation model. Market inputs can generally be verified and model selection does not involve significant management judgment.
Additional Information Regarding Level 3 Measurements
For valuations that include both observable and unobservable inputs, if the unobservable input is determined to be significant to the overall inputs, the entire valuation is categorized in Level 3. This includes derivatives valued using indicative price quotations for contracts with tenors that extend into periods with no observable pricing. In instances where observable data is unavailable, consideration is given to the assumptions that market participants would use in valuing the asset or liability. This includes assumptions about market risks such as liquidity, volatility and contract duration. Such instruments are categorized in Level 3 because the model inputs generally are not observable. PSEG considers credit and non-performance risk in the valuation of derivative contracts categorized in Levels 2 and 3, including both historical and current market data, in its assessment of credit and non-performance risk by counterparty. The impacts of credit and non-performance risk were not material to the financial statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The fair value of PSEG Power’s electric load contracts in which load consumption may change hourly based on demand are measured using certain unobservable inputs, such as historic load variability and, accordingly, are categorized as Level 3. The fair value of PSEG Power’s gas physical contracts at certain illiquid delivery locations are measured using average historical basis and, accordingly, are categorized as Level 3. While these physical gas contracts have an unobservable component in their respective forward price curves, the fluctuations in fair value have been driven primarily by changes in the observable inputs. The following tables provide details surrounding significant Level 3 valuations as of December 31, 2020 and 2019.
Quantitative Information About Level 3 Fair Value Measurements
Commodity Level 3 Position Fair Value as of December 31, 2020 Valuation
Technique(s) Significant
Unobservable Input Range Arithmetic Average
Assets (Liabilities)
Millions
PSEG Power
Electricity Electric Load Contracts $ 12 $ - Discounted Cash flow Load Shaping Cost 0% to 11%
4%
Gas Gas Physical Contracts - (2) Discounted Cash flow Historical Basis Adjustment '-60% to -30%
-43%
Electricity Other (A) - (3)
Total PSEG Power $ 12 $ (5)
Total PSEG $ 12 $ (5)
Quantitative Information About Level 3 Fair Value Measurements
Commodity Level 3 Position Fair Value as of December 31, 2019 Valuation
Technique(s) Significant
Unobservable Input Range
Assets (Liabilities)
Millions
PSEG Power
Electricity Electric Load Contracts $ 10 $ - Discounted Cash flow Historic Load Variability 0% to 10%
Gas Gas Physical Contracts - (3) Discounted Cash flow Average Historical Basis ‘-50% to 0%
Total PSEG Power $ 10 $ (3)
Total PSEG $ 10 $ (3)
(A)Other is comprised of a heat rate call option and capacity swaps.
As of December 31, 2020, significant unobservable inputs listed above would have a direct impact on the fair values of the above Level 3 instruments if they were adjusted. For energy-related contracts in cases where PSEG Power is a seller, an increase in the load variability would decrease the fair value. For gas-related contracts in cases where PSEG Power is a buyer, an increase in the average historical basis would increase the fair value.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
A reconciliation of the beginning and ending balances of Level 3 derivative contracts and securities for the years ended December 31, 2020 and 2019, respectively, follows:
Changes in Level 3 Assets and (Liabilities) Measured at Fair Value on a Recurring Basis
for the Year Ended December 31, 2020
Description Balance as of December 31, 2019 Total Gains or (Losses)
Realized/Unrealized
Included in Income (A) Purchases,
(Sales) Issuances/
Settlements
(B) Transfers
In/Out (C) Balance as of December 31, 2020
PSEG and PSEG Power
Net Derivative Assets (Liabilities) $ 7 $ 16 $ - $ (16) $ - $ 7
Changes in Level 3 Assets and (Liabilities) Measured at Fair Value on a Recurring Basis
for the Year Ended December 31, 2019
Description Balance as of December 31, 2018 Total Gains or (Losses)
Realized/Unrealized
Included in Income (A) Purchases, (Sales) Issuances/ Settlements (B) Transfers In/Out (C) Balance as of December 31, 2019
Millions
PSEG and PSEG Power
Net Derivative Assets (Liabilities) $ 1 $ 14 $ - $ (8) $ - $ 7
(A)Unrealized gains (losses) in the following table represent the change in derivative assets and liabilities still held as of December 31, 2020 and 2019.
Years Ended December 31,
2020 2019
Total Gains (Losses) Unrealized Gains (Losses) Total Gains (Losses) Unrealized Gains (Losses)
Millions
PSEG and PSEG Power
Operating Revenues $ 26 $ 1 $ 23 $ 12
Energy Costs (10) 1 (9) (6)
Total $ 16 $ 2 $ 14 $ 6
(B)Includes $(14) million and $(7) million in settlements for derivative contracts in 2020 and 2019.
(C)There were no transfers in 2020 and 2019 to or from Level 3.
As of December 31, 2020, PSEG carried $3.1 billion of net assets that are measured at fair value on a recurring basis, of which $7 million of net assets were measured using unobservable inputs and classified as Level 3 within the fair value hierarchy.
As of December 31, 2019, PSEG carried $2.6 billion of net assets that are measured at fair value on a recurring basis, of which $7 million of net assets were measured using unobservable inputs and classified as Level 3 within the fair value hierarchy.
Note 20. Stock Based Compensation
PSEG’s Amended and Restated 2004 Long-Term Incentive Plan (LTIP) is a broad-based equity compensation program that provides for grants of various long-term incentive compensation awards, such as stock options, stock appreciation rights, performance share units, restricted stock, restricted stock units, cash awards or any combination thereof. The types of long-term incentive awards that have been granted under the LTIP are non-qualified options to purchase shares of PSEG’s common stock, restricted stock unit awards and performance share unit awards. The type of equity award that is granted and the details of that award may vary from time to time and is subject to the approval of the Organization and Compensation Committee of PSEG’s Board of Directors (O&CC), the LTIP’s administrative committee.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The LTIP currently provides for the issuance of equity awards with respect to approximately 16 million shares of common stock. As of December 31, 2020, there were approximately 13 million shares available for future awards under the LTIP.
Stock Options
Under the LTIP, non-qualified options to acquire shares of PSEG common stock may be granted to officers and other key employees selected by the O&CC. Option awards are granted with an exercise price equal to the market price of PSEG’s common stock at the grant date. The options generally vest over four years of continuous service. Vesting schedules may be accelerated upon the occurrence of certain events, such as a change-in-control (unless substituted with an equity award of equal value), retirement, death or disability. Options are exercisable over a period of time designated by the O&CC (but not prior to one year or longer than ten years from the date of grant) and are subject to such other terms and conditions as the O&CC determines. Payment by option holders upon exercise of an option may be made in cash or, with the consent of the O&CC, by delivering previously acquired shares of PSEG common stock. No options have been granted since 2009.
Restricted Stock Units (RSUs)
Under the LTIP, PSEG has granted RSU awards to officers and other key employees. These awards, which are bookkeeping entries only, are subject to risk of forfeiture until vested by continued employment. Until distributed, the units are credited with dividend equivalent units (DEUs) proportionate to the dividends paid on PSEG common stock. Distributions are made in shares of common stock. The RSU grants for 2020 and 2019 generally vest at the end of three years. Vesting may be accelerated (pro-rated basis or full vesting) upon certain events such as change-in-control, retirement, disability or death.
Performance Share Units (PSUs)
Under the LTIP, PSEG has granted PSUs to officers and other key employees. These provide for distribution in shares of PSEG common stock based on achievement of certain financial goals over a three-year performance period. Following the end of the performance period, the payout varies from 0% to 200% of the number of PSUs granted depending on PSEG’s performance with respect to certain financial targets, including targets related to comparative performance against other companies in a peer group of energy companies. The PSUs are credited with DEUs proportionate to the dividends paid on PSEG common stock. Distributions are made in shares of common stock. Vesting may be accelerated on a pro-rated basis for the period of the employee’s service during the performance period as a result of certain events, such as change-in-control, retirement, death or disability.
Stock-Based Compensation
PSEG recognizes compensation expense for stock options based on their grant date fair values, which are determined using the Black-Scholes option-pricing model. Stock option awards are expensed on a tranche-specific basis over the requisite service period of the award. Ultimately, compensation expense for stock options is recognized for awards that vest.
PSEG recognizes compensation expense for RSUs over the vesting period based on the grant date fair value of the shares, which is equal to the closing market price of PSEG’s common stock on the date of the grant.
PSEG recognizes compensation expense for the total shareholder return (TSR) target for its PSU awards based on the grant date fair values of the award, which are determined using the Monte Carlo model. The following table provides the assumptions used to calculate the grant date fair value of the TSR portion of the PSU awards for 2020, 2019 and 2018:
Grant Date Risk-Free Interest Rate Volatility
February 18, 2020 1.36% 15.00%
February 19, 2019 2.47% 16.74%
February 20, 2018 2.36% 17.57%
The accrual of compensation cost is based on the probable achievement of the performance conditions, which result in a payout from 0% to 200% of the initial grant. PSEG recognizes compensation expense for the return on invested capital target for its PSUs based on the grant date fair value of the awards, which is equal to the market price of PSEG’s common stock on the date of the grant. The accrual during the year of grant is estimated at 100% of the original grant. Such accrual may be adjusted to reflect the actual outcome.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
2020 2019 2018
Millions
Compensation Cost included in O&M Expense $ 35 $ 33 $ 30
Income Tax Benefit Recognized in Consolidated Statement of Operations $ 10 $ 9 $ 9
For 2020, 2019 and 2018, PSEG also recorded excess tax benefits of $2 million, $5 million and $3 million, respectively.
PSEG recognizes compensation cost of awards issued over the shorter of the original vesting period or the period beginning on the date of grant and ending on the date an individual is eligible for retirement and the award vests.
Stock Options
As of January 1, 2019, there were 231,933 stock options outstanding, all of which were exercised in 2019 at a weighted average price of $33.49. There were no stock options granted or vested in 2020, 2019 and 2018.
Activity for options exercised for the years ended December 31, 2020, 2019 and 2018 is shown below:
2020 2019 2018
Millions
Total Intrinsic Value of Options Exercised $ - $ 5 $ 2
Cash Received from Options Exercised $ - $ 8 $ 4
Tax Benefit Realized from Options Exercised $ - $ 1 $ -
RSUs
Changes in RSUs for the year ended December 31, 2020 are summarized as follows:
Shares Weighted
Average Grant
Date Fair Value Weighted Average
Remaining Years
Contractual Term Aggregate
Intrinsic Value
Non-vested as of January 1, 2020 214,981 $ 50.41
Granted 219,749 $ 58.85
Vested 203,032 $ 55.20
Canceled/Forfeited 8,800 $ 54.13
Non-vested as of December 31, 2020 222,898 $ 54.21 0.9 $ 12,994,953
The weighted average grant date fair value per share for RSUs during the years ended December 31, 2020, 2019 and 2018 was $58.85, $56.24 and $49.34 per share, respectively.
The total intrinsic value of RSUs distributed during the years ended December 31, 2020, 2019 and 2018 was $11 million, $16 million and $12 million, respectively.
As of December 31, 2020, there was approximately $4 million of unrecognized compensation cost related to the RSUs, which is expected to be recognized over a weighted average period of 0.9 years. DEUs of 25,920 accrued on the RSUs during the year.
PSUs
Changes in PSUs for the year ended December 31, 2020 are summarized as follows:
Shares Weighted
Average Grant
Date Fair Value Weighted Average
Remaining Years
Contractual Term Aggregate
Intrinsic Value
Non-vested as of January 1, 2020 334,515 $ 59.30
Granted 447,815 $ 51.79
Vested 285,977 $ 54.96
Canceled/Forfeited 20,512 $ 58.37
Non-vested as of December 31, 2020 475,841 $ 54.88 1.7 $ 27,741,530
The weighted average grant date fair value per share for PSUs during the years ended December 31, 2020, 2019 and 2018 was $51.79, $62.17 and $54.95 per share, respectively.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The total intrinsic value of PSUs distributed during the years ended December 31, 2020, 2019 and 2018 was $19 million, $17 million and $17 million, respectively.
As of December 31, 2020, there was approximately $24 million of unrecognized compensation cost related to the PSUs, which is expected to be recognized over a weighted average period of 1.7 years. DEUs of 42,925 accrued on the PSUs during the year.
Outside Directors
Under the Directors Equity Plan, annually, on the first business day of May, each non-employee member of the Board of Directors is awarded stock units based on the amount of annual compensation to be paid at the closing price of PSEG common stock on that date. DEUs are credited quarterly and distributions will occur as specified by their election in accordance with the provisions of the Directors Equity Plan.
The fair value of these awards is recorded as compensation expense in the Consolidated Statements of Operations. Compensation expense for the plan was immaterial for each of the years ended December 31, 2020, 2019 and 2018.
ESPP
PSEG maintains an ESPP for all eligible employees of PSEG and its subsidiaries. Under the ESPP, shares of PSEG common stock may be purchased at 95% of the fair market value for represented employees and 90% for non-represented employees through payroll deductions. Dividends are to be paid out in cash unless the participant elects the dividends to be reinvested at fair market price. All employees are required to hold the shares purchased under the ESPP for at least three months from the purchase date. In any year, employees may purchase shares having a value not exceeding 10% of their base pay. Compensation expense recognized under this program was $1 million for the years ended December 31, 2020 and 2019 and immaterial for the year ended December 31, 2018.
During the years ended December 31, 2020, 2019 and 2018, employees purchased 373,682 shares, 280,077 shares and 286,559 shares, respectively, at an average price of $47.26, $54.67 and $47.44 per share, respectively. As of December 31, 2020, 2.2 million shares were available for future issuance under this plan.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 21. Other Income (Deductions)
PSE&G PSEG Power Other (A) Consolidated
Total
Millions
Year Ended December 31, 2020
NDT Fund Interest and Dividends $ - $ 52 $ - $ 52
Allowance for Funds Used During Construction 87 - - 87
Solar Loan Interest 15 - - 15
Donations - - (3) (3)
Purchase of Tax Losses under New Jersey Technology Tax Benefit Transfer Program - (36) - (36)
Other 6 (4) (2) -
Total Other Income (Deductions) $ 108 $ 12 $ (5) $ 115
Year Ended December 31, 2019
NDT Fund Interest and Dividends $ - $ 57 $ - $ 57
Allowance for Funds Used During Construction 59 - - 59
Solar Loan Interest 16 - - 16
Donations - - (11) (11)
Other 8 (3) (1) 4
Total Other Income (Deductions) $ 83 $ 54 $ (12) $ 125
Year Ended December 31, 2018
NDT Fund Interest and Dividends $ - $ 52 $ - $ 52
Allowance for Funds Used During Construction 54 - - 54
Solar Loan Interest 18 - - 18
Donations - - (17) (17)
Purchase of Tax Losses under New Jersey Technology Tax Benefit Transfer Program - (26) - (26)
Other 8 (5) 1 4
Total Other Income (Deductions) $ 80 $ 21 $ (16) $ 85
(A)Other consists of activity at PSEG (as parent company), Energy Holdings, Services, PSEG LI and intercompany eliminations.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 22. Income Taxes
A reconciliation of reported income tax expense for PSEG with the amount computed by multiplying pre-tax income by the statutory federal income tax rate of 21% is as follows:
Years Ended December 31,
PSEG 2020 2019 2018
Millions
Net Income $ 1,905 $ 1,693 $ 1,438
Income Taxes:
Operating Income:
Current (Benefit) Expense:
Federal $ 385 $ 84 $ (97)
State 48 18 83
Total Current 433 102 (14)
Deferred Expense (Benefit):
Federal (164) 3 373
State 141 132 71
Total Deferred (23) 135 444
ITC (14) 20 (13)
Total Income Tax Expense (Benefit) $ 396 $ 257 $ 417
Pre-Tax Income $ 2,301 $ 1,950 $ 1,855
Tax Computed at Statutory Rate @ 21% $ 483 $ 410 $ 390
Increase (Decrease) Attributable to Flow-Through of Certain Tax Adjustments:
State Income Taxes (net of federal income tax) 147 117 123
Uncertain Tax Positions 3 - (24)
NDT Fund 32 34 (13)
Plant-Related Items (9) (2) (10)
Tax Credits (18) (18) (16)
Audit Settlement (27) - -
Leasing Activities (35) - -
Tax Adjustment Credit (205) (272) (30)
Deferred Tax Expense (Benefit) - Tax Act - - 3
Bad Debt Flow-Through 28 - -
Other (3) (12) (6)
Subtotal (87) (153) 27
Total Income Tax Expense (Benefit) $ 396 $ 257 $ 417
Effective Income Tax Rate 17.2 % 13.2 % 22.5 %
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following is an analysis of deferred income taxes for PSEG:
As of December 31,
PSEG 2020 2019
Millions
Deferred Income Taxes
Assets:
Noncurrent:
Regulatory Liability Excess Deferred Tax $ 485 $ 539
OPEB 135 151
Related to Uncertain Tax Positions 29 97
Interest Disallowance Carry Forward 39 76
Operating Leases 60 64
Other 170 128
Total Noncurrent Assets $ 918 $ 1,055
Liabilities:
Noncurrent:
Plant-Related Items $ 5,163 $ 5,051
New Jersey Corporate Business Tax 1,016 876
Leasing Activities 133 284
AROs and NDT Fund 324 277
Taxes Recoverable Through Future Rates (net) 114 108
Pension Costs 97 98
Operating Leases 55 59
Other 247 273
Total Noncurrent Liabilities $ 7,149 $ 7,026
Summary of Accumulated Deferred Income Taxes:
Net Noncurrent Deferred Income Tax Liabilities $ 6,231 $ 5,971
ITC 271 285
Net Total Noncurrent Deferred Income Taxes and ITC $ 6,502 $ 6,256
The deferred tax effect of certain assets and liabilities is presented in the table above net of the deferred tax effect associated with the respective regulatory deferrals.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
A reconciliation of reported income tax expense for PSE&G with the amount computed by multiplying pre-tax income by the statutory federal income tax rate of 21% is as follows:
Years Ended December 31,
PSE&G 2020 2019 2018
Millions
Net Income $ 1,327 $ 1,250 $ 1,067
Income Taxes:
Operating Income:
Current (Benefit) Expense:
Federal $ 179 $ 121 $ (62)
State 8 - 1
Total Current 187 121 (61)
Deferred Expense (Benefit):
Federal (71) (156) 287
State 128 117 122
Total Deferred 57 (39) 409
ITC (4) 11 (4)
Total Income Tax Expense $ 240 $ 93 $ 344
Pre-Tax Income $ 1,567 $ 1,343 $ 1,411
Tax Computed at Statutory Rate @ 21% $ 329 $ 282 $ 296
Increase (Decrease) Attributable to Flow-Through of Certain Tax Adjustments:
State Income Taxes (net of federal income tax) 106 92 98
Uncertain Tax Positions 4 1 (1)
Plant-Related Items (9) (2) (10)
Tax Credits (9) (8) (8)
Audit Settlement (2) - -
Tax Adjustment Credit (205) (272) (30)
Bad Debt Flow-Through 28 - -
Other (2) - (1)
Subtotal (89) (189) 48
Total Income Tax Expense $ 240 $ 93 $ 344
Effective Income Tax Rate 15.3 % 6.9 % 24.4 %
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following is an analysis of deferred income taxes for PSE&G:
As of December 31,
PSE&G 2020 2019
Millions
Deferred Income Taxes
Assets:
Noncurrent:
Regulatory Liability Excess Deferred Tax $ 485 $ 539
OPEB 82 97
Related to Uncertain Tax Positions - 42
Operating Leases 21 21
Other 92 55
Total Noncurrent Assets $ 680 $ 754
Liabilities:
Noncurrent:
Plant-Related Items $ 3,874 $ 3,754
New Jersey Corporate Business Tax 721 588
Pension Costs 166 160
Taxes Recoverable Through Future Rates (net) 114 108
Conservation Costs 61 44
Operating Leases 21 21
Related to Uncertain Tax Positions 5 -
Other 161 183
Total Noncurrent Liabilities $ 5,123 $ 4,858
Summary of Accumulated Deferred Income Taxes:
Net Noncurrent Deferred Income Tax Liabilities $ 4,443 $ 4,104
ITC 81 85
Net Total Noncurrent Deferred Income Taxes and ITC $ 4,524 $ 4,189
The deferred tax effect of certain assets and liabilities is presented in the table above net of the deferred tax effect associated with the respective regulatory deferrals.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
A reconciliation of reported income tax expense for PSEG Power with the amount computed by multiplying pre-tax income by the statutory federal income tax rate of 21% is as follows:
Years Ended December 31,
PSEG Power 2020 2019 2018
Millions
Net Income $ 594 $ 468 $ 365
Income Taxes:
Operating Income:
Current (Benefit) Expense:
Federal $ 135 $ (48) $ (164)
State (7) 3 24
Total Current 128 (45) (140)
Deferred Expense (Benefit):
Federal 39 208 214
State 31 31 1
Total Deferred 70 239 215
ITC (10) 9 (9)
Total Income Tax Expense (Benefit) $ 188 $ 203 $ 66
Pre-Tax Income $ 782 $ 671 $ 431
Tax Computed at Statutory Rate @ 21% $ 164 $ 141 $ 91
Increase (Decrease) Attributable to Flow-Through of Certain Tax Adjustments:
State Income Taxes (net of federal income tax) 18 25 21
NDT Fund 32 34 (13)
Tax Credits (9) (10) (7)
Uncertain Tax Positions 5 11 (24)
Audit Settlement (21) - -
Deferred Tax Benefit - Tax Act - - (1)
Other (1) 2 (1)
Subtotal 24 62 (25)
Total Income Tax Expense (Benefit) $ 188 $ 203 $ 66
Effective Income Tax Rate 24.0 % 30.3 % 15.3 %
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following is an analysis of deferred income taxes for PSEG Power:
As of December 31,
PSEG Power 2020 2019
Millions
Deferred Income Taxes
Assets:
Noncurrent:
Related to Uncertain Tax Positions $ 38 $ 72
Pension Costs 68 61
OPEB 41 40
Operating Leases 13 15
Interest Disallowance Carry Forward 6 12
Contractual Liabilities & Environmental Costs 6 7
Other 36 30
Total Noncurrent Assets $ 208 $ 237
Liabilities:
Noncurrent:
Plant-Related Items $ 1,286 $ 1,292
New Jersey Corporate Business Tax 308 282
AROs and NDT Fund 325 278
Operating Leases 13 15
Other 21 45
Total Noncurrent Liabilities $ 1,953 $ 1,912
Summary of Accumulated Deferred Income Taxes:
Net Noncurrent Deferred Income Tax Liabilities $ 1,745 $ 1,675
ITC 191 201
Net Total Noncurrent Deferred Income Taxes and ITC $ 1,936 $ 1,876
PSEG, PSE&G and PSEG Power each provide deferred taxes at the enacted statutory tax rate for all temporary differences between the financial statement carrying amounts and the tax bases of assets and liabilities irrespective of the treatment for rate-making purposes. Management believes that it is probable that the accumulated tax benefits that previously have been treated as a flow-through item to PSE&G customers will be recovered from or refunded to PSE&G’s customers in the future. See Note 7. Regulatory Assets and Liabilities.
Effective January 1, 2018, the Tax Act established tax laws including, among other things, the reduction of the corporate income tax rate from a maximum of 35% to 21%, a limitation on deductible interest, and limitations on the utilization of net operating losses (NOLs).
The 2018 decrease in the federal tax rate resulted in PSE&G recording excess deferred income taxes. As of December 31, 2019, the balance was approximately $1.9 billion with a Regulatory Liability of approximately $2.6 billion. In 2020, PSE&G returned approximately $286 million of excess deferred income taxes and previously realized and current period deferred income taxes related to tax repair deductions to its customers with a reduction to tax expense of approximately $205 million. The flowback to customers of the excess deferred income taxes and previously realized tax repair deductions resulted in a decrease of approximately $255 million in the Regulatory Liability. The current period tax repair deduction reduces tax expense and revenue and recognizes a Regulatory Asset as PSE&G believes it is probable that the current period tax repair deductions flowed through to the customers will be recovered from customers in the future. See Note 7. Regulatory Assets and Liabilities for additional information.
In March 2020, the federal Coronavirus Aid, Relief, and Economic Security Act (CARES Act) was enacted. Among other provisions, the CARES Act allows a five-year carryback of any NOL generated in a taxable year beginning after December 31, 2017, and before January 1, 2021.
In April 2020, the IRS issued a PLR to PSE&G concluding that certain excess deferred taxes previously classified as protected should be classified as unprotected. Unprotected excess deferred income taxes are not subject to the normalization rules
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
allowing them to be refunded to customers sooner as agreed to with FERC and the BPU. In July 2020, FERC and the BPU approved PSE&G’s requests to refund these unprotected excess deferred income taxes to customers. FERC approved the refund of these unprotected excess deferred income taxes within the 2019 true-up filing. The BPU approved the refund of these unprotected excess deferred income taxes within the next five years beginning in July 2020. See Note 7. Regulatory Assets and Liabilities for additional information.
In July 2020, the IRS issued final and proposed regulations addressing the limitation on deductible business interest expense contained in the Tax Act. These regulations retroactively allow depreciation to be added back in computing the 30% adjusted taxable income (ATI) cap, increasing the amount of interest that can be deducted by unregulated businesses in years before 2022. For 2022 and after, the regulations continue to disallow the addback of depreciation in the computation of ATI, effectively lowering the cap on the amount of deductible business interest and contain special rules in allocating interest between regulated and non-regulated businesses. The portion of PSEG’s and PSEG Power’s business interest expense that was disallowed in 2018 and 2019 under the previously issued proposed regulations will now be deductible in those respective years. These regulations remain uncertain in some respects.
In late December 2020, the Consolidated Appropriations Act (CAA), 2021 was enacted. PSEG’s initial analysis of the CAA indicates that this legislation will not have a material impact on the financial condition and cash flows of PSEG, PSE&G and PSEG Power.
We expect that a prolonged coronavirus pandemic or economic recovery may result in additional federal or state tax legislation which can have a material impact on PSEG’s, PSE&G’s and PSEG Power’s tax expense and cash tax position.
Amounts recorded under the Tax Act, CARES Act and CAA, including depreciation and interest disallowance regulations, are subject to change based on several factors, including, among other things, whether the IRS or state taxing authorities issue additional guidance and/or further clarification. Any further guidance or clarification could impact PSEG’s, PSE&G’s and PSEG Power’s financial statements.
As of December 31, 2020, PSE&G had a $29 million New Jersey Corporate Business Tax NOL that is expected to be fully realized in the future. There are no other material tax carryforwards in other jurisdictions.
PSEG recorded the following amounts related to its unrecognized tax benefits, which were primarily comprised of amounts recorded for PSE&G, PSEG Power and Energy Holdings:
2020 PSEG PSE&G PSEG Power Energy
Holdings
Millions
Total Amount of Unrecognized Tax Benefits as of January 1, 2020 $ 321 $ 124 $ 161 $ 33
Increases as a Result of Positions Taken in a Prior Period 33 21 10 1
Decreases as a Result of Positions Taken in a Prior Period (91) (51) (36) (4)
Increases as a Result of Positions Taken during the Current Period - - - -
Decreases as a Result of Positions Taken during the Current Period - - - -
Decreases as a Result of Settlements with Taxing Authorities (116) (64) (52) -
Decreases due to Lapses of Applicable Statute of Limitations - - - -
Total Amount of Unrecognized Tax Benefits as of December 31, 2020 $ 147 $ 30 $ 83 $ 30
Accumulated Deferred Income Taxes Associated with Unrecognized Tax Benefits (69) (12) (49) (8)
Regulatory Asset-Unrecognized Tax Benefits (15) (15) - -
Total Amount of Unrecognized Tax Benefits that if Recognized, would Impact the Effective Tax Rate (including Interest and Penalties) $ 63 $ 3 $ 34 $ 22
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
2019 PSEG PSE&G PSEG Power Energy
Holdings
Millions
Total Amount of Unrecognized Tax Benefits as of January 1, 2019 $ 318 $ 108 $ 151 $ 54
Increases as a Result of Positions Taken in a Prior Period 17 5 8 5
Decreases as a Result of Positions Taken in a Prior Period (37) (1) (13) (22)
Increases as a Result of Positions Taken during the Current Period 27 12 15 -
Decreases as a Result of Positions Taken during the Current Period - - - -
Decreases as a Result of Settlements with Taxing Authorities (4) - - (4)
Decreases due to Lapses of Applicable Statute of Limitations - - - -
Total Amount of Unrecognized Tax Benefits as of December 31, 2019 $ 321 $ 124 $ 161 $ 33
Accumulated Deferred Income Taxes Associated with Unrecognized Tax Benefits (184) (71) (105) (7)
Regulatory Asset-Unrecognized Tax Benefits (46) (46) - -
Total Amount of Unrecognized Tax Benefits that if Recognized, would Impact the Effective Tax Rate (including Interest and Penalties) $ 91 $ 7 $ 56 $ 26
2018 PSEG PSE&G PSEG Power Energy
Holdings
Millions
Total Amount of Unrecognized Tax Benefits as of January 1, 2018 $ 334 $ 135 $ 142 $ 53
Increases as a Result of Positions Taken in a Prior Period 11 4 4 3
Decreases as a Result of Positions Taken in a Prior Period (70) (31) (37) (2)
Increases as a Result of Positions Taken during the Current Period 52 3 48 -
Decreases as a Result of Positions Taken during the Current Period (3) (3) - -
Decreases as a Result of Settlements with Taxing Authorities (6) - (6) -
Decreases due to Lapses of Applicable Statute of Limitations - - - -
Total Amount of Unrecognized Tax Benefits as of December 31, 2018 $ 318 $ 108 $ 151 $ 54
Accumulated Deferred Income Taxes Associated with Unrecognized Tax Benefits (173) (57) (104) (12)
Regulatory Asset-Unrecognized Tax Benefits (46) (46) - -
Total Amount of Unrecognized Tax Benefits that if Recognized, would Impact the Effective Tax Rate (including Interest and Penalties) $ 99 $ 5 $ 47 $ 42
In April 2020, the Joint Committee on Taxation approved PSEG’s nuclear carryback claim and federal tax returns for the years 2011 and 2012. In June 2020, the federal income tax audits for years 2011 through 2016 and the nuclear carryback claim were concluded.
PSEG and its subsidiaries include accrued interest and penalties related to uncertain tax positions required to be recorded as Income Tax Expense in the Consolidated Statements of Operations. Accumulated interest and penalties that are recorded on the Consolidated Balance Sheets on uncertain tax positions were as follows:
Accumulated Interest and Penalties
on Uncertain Tax Positions
as of December 31,
2020 2019 2018
Millions
PSEG $ 29 $ 40 $ 43
PSE&G $ 9 $ 16 $ 12
PSEG Power $ 5 $ 12 $ 9
Energy Holdings $ 15 $ 13 $ 22
It is reasonably possible that total unrecognized tax benefits will significantly increase or decrease within the next twelve months due to either agreements with various taxing authorities upon audit, the expiration of the Statute of Limitations, or other pending tax matters. These potential increases or decreases are as follows:
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Possible (Increase)/Decrease in Total Unrecognized Tax Benefits Over the next
12 Months
Millions
PSEG $ 12
PSE&G $ 12
PSEG Power $ -
A description of income tax years that remain subject to examination by material jurisdictions, where an examination has not already concluded are:
PSEG PSE&G PSEG Power
United States
Federal 2017-2019 N/A N/A
New Jersey 2011-2019 2011-2019 N/A
Pennsylvania 2017-2019 2017-2019 N/A
Connecticut 2016-2019 N/A N/A
Maryland 2017-2019 N/A N/A
New York 2017-2019 N/A N/A
New Jersey State Tax Reform
In September 2020, New Jersey enacted its State Fiscal Year 2021 Budget, which amended the temporary surtax originally enacted into law in 2018, from 1.5% to 2.5% for 2020 and 2021 and extended the 2.5% surtax to 2023. PSE&G continues to be exempt and this amendment will not have a material impact on PSEG’s and PSEG Power’s financial statements.
In July 2018, New Jersey made changes to its income tax laws, including imposing the aforementioned temporary surtax, as well as requiring corporate taxpayers to file in a combined reporting group as defined under New Jersey law starting in 2019. Both provisions include an exemption for public utilities. PSEG believes PSE&G meets the definition of a public utility and, therefore, will not be impacted by the temporary surtax or be included in the combined reporting group. PSEG anticipates New Jersey will be issuing clarifying guidance regarding combined reporting rules. Any further guidance or clarification could impact PSEG’s and PSEG Power’s financial statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 23. Accumulated Other Comprehensive Income (Loss), Net of Tax
PSEG Other Comprehensive Income (Loss)
Accumulated Other Comprehensive Income (Loss) Cash Flow Hedges Pension and OPEB Plans Available-for -Sale Securities Total
Millions
Balance as of December 31, 2017 $ - $ (406) $ 177 $ (229)
Cumulative Effect Adjustment to Reclassify Unrealized Net Gains on Equity Investments to Retained Earnings - - (176) (176)
Current Period Other Comprehensive Income (Loss)
Other Comprehensive Income (Loss) before Reclassifications (1) 17 (25) (9)
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) - 29 8 37
Net Current Period Other Comprehensive Income (Loss) (1) 46 (17) 28
Net Change in Accumulated Other Comprehensive Income (Loss) (1) 46 (193) (148)
Balance as of December 31, 2018 $ (1) $ (360) $ (16) $ (377)
Cumulative Effect Adjustment to Reclassify Stranded Tax Effects Resulting in the Change in the Federal Corporate Income Tax to Retained Earnings - (81) - (81)
Current Period Other Comprehensive Income (Loss)
Other Comprehensive Income (Loss) before Reclassifications (17) (70) 49 (38)
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) 3 12 (8) 7
Net Current Period Other Comprehensive Income (Loss) (14) (58) 41 (31)
Net Change in Accumulated Other Comprehensive Income (Loss) (14) (139) 41 (112)
Balance as of December 31, 2019 $ (15) $ (499) $ 25 $ (489)
Other Comprehensive Income (Loss) before Reclassifications (4) (58) 51 (11)
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) 10 12 (26) (4)
Net Current Period Other Comprehensive Income (Loss) 6 (46) 25 (15)
Balance as of December 31, 2020 $ (9) $ (545) $ 50 $ (504)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PSEG Power Other Comprehensive Income (Loss)
Accumulated Other Comprehensive Income (Loss) Cash Flow Hedges Pension and OPEB Plans Available-for -Sale Securities Total
Millions
Balance as of December 31, 2017 $ - $ (347) $ 175 $ (172)
Cumulative Effect Adjustment to Reclassify Unrealized Net Gains on Equity Investments to Retained Earnings - - (175) (175)
Current Period Other Comprehensive Income (Loss)
Other Comprehensive Income (Loss) before Reclassifications - 16 (19) (3)
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) - 25 6 31
Net Current Period Other Comprehensive Income (Loss) - 41 (13) 28
Net Change in Accumulated Other Comprehensive Income (Loss) - 41 (188) (147)
Balance as of December 31, 2018 $ - $ (306) $ (13) $ (319)
Cumulative Effect Adjustment to Reclassify Stranded Tax Effects Resulting in the Change in the Federal Corporate Income Tax to Retained Earnings - (69) - (69)
Current Period Other Comprehensive Income (Loss)
Other Comprehensive Income (Loss) before Reclassifications - (55) 38 (17)
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) - 10 (6) 4
Net Current Period Other Comprehensive Income (Loss) - (45) 32 (13)
Net Change in Accumulated Other Comprehensive Income (Loss) - (114) 32 (82)
Balance as of December 31, 2019 $ - $ (420) $ 19 $ (401)
Other Comprehensive Income (Loss) before Reclassifications - (48) 41 (7)
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) - 9 (20) (11)
Net Current Period Other Comprehensive Income (Loss) - (39) 21 (18)
Balance as of December 31, 2020 $ - $ (459) $ 40 $ (419)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PSEG Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement
Year Ended December 31, 2018
Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) Location of Pre-Tax Amount in Statement of Operations Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount
Millions
Pension and OPEB Plans
Amortization of Prior Service (Cost) Credit Non-Operating Pension and OPEB Credits (Costs) $ 6 $ (2) $ 4
Amortization of Actuarial Loss Non-Operating Pension and OPEB Credits (Costs) (47) 14 (33)
Total Pension and OPEB Plans (41) 12 (29)
Available-for-Sale Securities
Realized Gains (Losses) Net Gains (Losses) on Trust Investments (13) 5 (8)
Total Available-for-Sale Securities (13) 5 (8)
Total $ (54) $ 17 $ (37)
PSEG Power Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement
Year Ended December 31, 2018
Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) Location of Pre-Tax Amount in Statement of Operations Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount
Millions
Pension and OPEB Plans
Amortization of Prior Service (Cost) Credit Non-Operating Pension and OPEB Credits (Costs) $ 5 $ (1) $ 4
Amortization of Actuarial Loss Non-Operating Pension and OPEB Credits (Costs) (40) 11 (29)
Total Pension and OPEB Plans (35) 10 (25)
Available-for-Sale Securities
Realized Gains (Losses) Net Gains (Losses) on Trust Investments (11) 5 (6)
Total Available-for-Sale Securities (11) 5 (6)
Total $ (46) $ 15 $ (31)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PSEG Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement
Year Ended December 31, 2019
Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) Location of Pre-Tax Amount in Statement of Operations Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount
Millions
Cash Flow Hedges
Interest Rate Swaps Interest Expense $ (4) $ 1 $ (3)
Total Cash Flow Hedges (4) 1 (3)
Pension and OPEB Plans
Amortization of Prior Service (Cost) Credit Non-Operating Pension and OPEB Credits (Costs) 26 (7) 19
Amortization of Actuarial Loss Non-Operating Pension and OPEB Credits (Costs) (43) 12 (31)
Total Pension and OPEB Plans (17) 5 (12)
Available-for-Sale Securities
Realized Gains (Losses) Net Gains (Losses) on Trust Investments 13 (5) 8
Total Available-for-Sale Securities 13 (5) 8
Total $ (8) $ 1 $ (7)
PSEG Power Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement
Year Ended December 31, 2019
Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) Location of Pre-Tax Amount in Statement of Operations Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount
Millions
Pension and OPEB Plans
Amortization of Prior Service (Cost) Credit Non-Operating Pension and OPEB Credits (Costs) $ 23 $ (7) $ 16
Amortization of Actuarial Loss Non-Operating Pension and OPEB Credits (Costs) (36) 10 (26)
Total Pension and OPEB Plans (13) 3 (10)
Available-for-Sale Securities
Realized Gains (Losses) Net Gains (Losses) on Trust Investments 10 (4) 6
Total Available-for-Sale Securities 10 (4) 6
Total $ (3) $ (1) $ (4)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PSEG Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement
Year Ended December 31, 2020
Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) Location of Pre-Tax Amount in Statement of Operations Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount
Millions
Cash Flow Hedges
Interest Rate Swaps Interest Expense $ (14) $ 4 $ (10)
Total Cash Flow Hedges (14) 4 (10)
Pension and OPEB Plans
Amortization of Prior Service (Cost) Credit Non-Operating Pension and OPEB Credits (Costs) 24 (7) 17
Amortization of Actuarial Loss Non-Operating Pension and OPEB Credits (Costs) (40) 11 (29)
Total Pension and OPEB Plans (16) 4 (12)
Available-for-Sale Securities
Realized Gains (Losses) and Impairments Net Gains (Losses) on Trust Investments 42 (16) 26
Total Available-for-Sale Securities 42 (16) 26
Total $ 12 $ (8) $ 4
PSEG Power Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement
Year Ended December 31, 2020
Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) Location of Pre-Tax Amount in Statement of Operations Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount
Millions
Pension and OPEB Plans
Amortization of Prior Service (Cost) Credit Non-Operating Pension and OPEB Credits (Costs) $ 21 $ (6) $ 15
Amortization of Actuarial Loss Non-Operating Pension and OPEB Credits (Costs) (34) 10 (24)
Total Pension and OPEB Plans (13) 4 (9)
Available-for-Sale Securities
Realized Gains (Losses) and Impairments Net Gains (Losses) on Trust Investments 34 (14) 20
Total Available-for-Sale Securities 34 (14) 20
Total $ 21 $ (10) $ 11
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 24. Earnings Per Share (EPS) and Dividends
EPS
Diluted EPS is calculated by dividing Net Income by the weighted average number of shares of common stock outstanding, including shares issuable upon exercise of stock options outstanding or vesting of restricted stock awards granted under PSEG’s stock compensation plans and upon payment of PSUs or RSUs. For additional information on PSEG’s stock compensation plans see Note 20. Stock Based Compensation. The following table shows the effect of these stock options, PSUs and RSUs on the weighted average number of shares outstanding used in calculating diluted EPS:
Years Ended December 31,
2020 2019 2018
Basic Diluted Basic Diluted Basic Diluted
EPS Numerator:
(Millions)
Net Income $ 1,905 $ 1,905 $ 1,693 $ 1,693 $ 1,438 $ 1,438
EPS Denominator:
(Millions)
Weighted Average Common Shares Outstanding 504 504 504 504 504 504
Effect of Stock Based Compensation Awards - 3 - 3 - 3
Total Shares 504 507 504 507 504 507
EPS:
Net Income $ 3.78 $ 3.76 $ 3.35 $ 3.33 $ 2.85 $ 2.83
For additional information on all the types of long-term incentive awards, see Note 20. Stock Based Compensation.
Dividends
Years Ended December 31,
Dividend Payments on Common Stock 2020 2019 2018
Per Share $ 1.96 $ 1.88 $ 1.80
in Millions $ 991 $ 950 $ 910
On February 16, 2021, PSEG’s Board of Directors approved a $0.51 per share common stock dividend for the first quarter of 2021.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 25. Financial Information by Business Segment
Basis of Organization
PSEG’s, PSE&G’s and PSEG Power’s operating segments were determined by management in accordance with GAAP. These segments were determined based on how management measures performance based on segment Net Income, as illustrated in the following table, and how resources are allocated to each business. PSEG’s reportable segments are PSE&G and PSEG Power. PSE&G and PSEG Power each represent a single reportable segment and therefore no separate segment information is provided for these Registrants.
PSE&G
PSE&G earns revenues from its tariffs, under which it provides electric transmission and electric and gas distribution services to residential, commercial and industrial customers in New Jersey. The rates charged for electric transmission are regulated by FERC while the rates charged for electric and gas distribution are regulated by the BPU. Revenues are also earned from several other activities such as solar investments, sundry sales, the appliance service business, wholesale transmission services and other miscellaneous services.
PSEG Power
PSEG Power earns revenues by selling energy, capacity and ancillary services on a wholesale basis under contract to power marketers and to load-serving entities and by bidding energy, capacity and ancillary services into the markets for these products. A significant portion of PSEG Power’s revenue is obtained from the various ISOs in which PSEG Power operates. The ISOs act similarly to a clearing house for all of its members in that all revenues paid out are collected from market participants based on their consumption of energy and energy-related products. PSEG Power also enters into bilateral contracts for energy, capacity, FTRs, gas, emission allowances and other energy-related contracts to optimize the value of its portfolio of generating assets and its electric and gas supply obligations. In addition, PSEG Power’s Salem 1, Salem 2 and Hope Creek nuclear plants receive ZEC revenue from the EDCs in New Jersey including PSE&G.
Other
This category includes amounts applicable to Energy Holdings and PSEG LI, which are below the quantitative threshold for separate disclosure as reportable segments. Other also includes amounts applicable to PSEG (parent corporation) and Services.
PSE&G PSEG Power Other (A) Eliminations (B) Consolidated
Total
Millions
Year Ended December 31, 2020
Operating Revenues $ 6,608 $ 3,634 $ 595 $ (1,234) $ 9,603
Depreciation and Amortization 887 368 30 - 1,285
Operating Income (Loss) 1,639 603 28 - 2,270
Income from Equity Method Investments - 14 - - 14
Interest Income 17 6 5 (3) 25
Interest Expense 388 121 94 (3) 600
Income (Loss) before Income Taxes 1,567 782 (48) - 2,301
Income Tax Expense (Benefit) 240 188 (32) - 396
Net Income (Loss) (C) $ 1,327 $ 594 $ (16) $ - $ 1,905
Gross Additions to Long-Lived Assets $ 2,507 $ 404 $ 12 $ - $ 2,923
As of December 31, 2020
Total Assets $ 35,581 $ 12,704 $ 2,692 $ (927) $ 50,050
Investments in Equity Method Subsidiaries $ - $ 64 $ - $ - $ 64
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PSE&G PSEG Power Other (A) Eliminations (B) Consolidated
Total
Millions
Year Ended December 31, 2019
Operating Revenues $ 6,625 $ 4,385 $ 549 $ (1,483) $ 10,076
Depreciation and Amortization 837 377 34 - 1,248
Operating Income (Loss) 1,469 448 26 - 1,943
Income from Equity Method Investments - 14 - - 14
Interest Income 18 7 6 (5) 26
Interest Expense 361 119 94 (5) 569
Income (Loss) before Income Taxes 1,343 671 (64) - 1,950
Income Tax Expense (Benefit) 93 203 (39) - 257
Net Income (Loss) (C) $ 1,250 $ 468 $ (25) $ - $ 1,693
Gross Additions to Long-Lived Assets $ 2,542 $ 607 $ 17 $ - $ 3,166
As of December 31, 2019
Total Assets $ 33,266 $ 12,805 $ 2,715 $ (1,056) $ 47,730
Investments in Equity Method Subsidiaries $ - $ 66 $ 1 $ - $ 67
PSE&G PSEG Power Other (A) Eliminations (B) Consolidated
Total
Millions
Year Ended December 31, 2018
Operating Revenues $ 6,471 $ 4,146 $ 571 $ (1,492) $ 9,696
Depreciation and Amortization 770 354 34 - 1,158
Operating Income (Loss) 1,606 596 96 - 2,298
Income from Equity Method Investments - 15 - - 15
Interest Income 21 5 9 (6) 29
Interest Expense 333 76 73 (6) 476
Income (Loss) before Income Taxes 1,411 431 13 - 1,855
Income Tax Expense (Benefit) 344 66 7 - 417
Net Income (Loss) $ 1,067 $ 365 $ 6 $ - $ 1,438
Gross Additions to Long-Lived Assets $ 2,896 $ 996 $ 20 $ - $ 3,912
As of December 31, 2018
Total Assets $ 31,109 $ 12,594 $ 2,604 $ (981) $ 45,326
Investments in Equity Method Subsidiaries $ - $ 86 $ - $ - $ 86
(A)Includes amounts applicable to Energy Holdings and PSEG LI, which are below the quantitative threshold for separate disclosure as reportable segments. Other also includes amounts applicable to PSEG (parent corporation) and Services.
(B)Intercompany eliminations primarily relate to intercompany transactions between PSE&G and PSEG Power. For a further discussion of the intercompany transactions between PSE&G and PSEG Power, see Note 26. Related-Party Transactions.
(C)Includes an after-tax gain of $86 million in the year ended December 31, 2020 related to the sale of PSEG Power’s interest in the Yards Creek generation facility and an after-tax loss of $286 million in the year ended December 31, 2019 related to the sale of PSEG Power’s ownership interests in the Keystone and Conemaugh fossil generation plants. See Note 4. Early Plant Retirements/Asset Dispositions for additional information.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 26. Related-Party Transactions
The following discussion relates to intercompany transactions, which are eliminated during the PSEG consolidation process in accordance with GAAP.
PSE&G
The financial statements for PSE&G include transactions with related parties presented as follows:
Years Ended December 31,
Related Party Transactions 2020 2019 2018
Millions
Billings from Affiliates:
Net Billings from PSEG Power (A) $ 1,207 $ 1,512 $ 1,514
Administrative Billings from Services (B) 337 310 333
Total Billings from Affiliates $ 1,544 $ 1,822 $ 1,847
Years Ended December 31,
Related Party Transactions 2020 2019
Millions
Receivables from PSEG (C) $ - $ 1
Payable to PSEG Power (A) $ 273 $ 307
Payable to Services (B) 95 83
Payable to PSEG (C) 111 -
Accounts Payable-Affiliated Companies $ 479 $ 390
Working Capital Advances to Services (D) $ 33 $ 33
Long-Term Accrued Taxes Payable $ 7 $ 115
PSEG Power
The financial statements for PSEG Power include transactions with related parties presented as follows:
Years Ended December 31,
Related Party Transactions 2020 2019 2018
Millions
Billings to Affiliates:
Net Billings to PSE&G (A) $ 1,207 $ 1,512 1,514
Billings from Affiliates:
Administrative Billings from Services (B) $ 160 $ 156 $ 145
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Years Ended December 31,
Related Party Transactions 2020 2019
Millions
Receivable from PSE&G (A) $ 273 $ 307
Receivables from PSEG (C) 44 101
Accounts Receivable-Affiliated Companies $ 317 $ 408
Payable to Services (B) $ 13 $ 5
Accounts Payable-Affiliated Companies $ 13 $ 5
Short-Term Loan to (from) Affiliate (E) $ 161 $ 149
Working Capital Advances to Services (D) $ 17 $ 17
Long-Term Accrued Taxes Payable $ 57 $ 115
(A)PSE&G has entered into a requirements contract with PSEG Power under which PSEG Power provides the gas supply services needed to meet PSE&G’s BGSS and other contractual requirements. PSEG Power has also entered into contracts to supply energy, capacity and ancillary services to PSE&G through the BGS auction process and sells ZECs to PSE&G under the ZEC program. The rates in the BGS and BGSS contracts and for the ZEC sales are prescribed by the BPU. BGS and BGSS sales are billed and settled on a monthly basis. ZEC sales are billed on a monthly basis and settled annually following completion of each energy year. In addition, PSEG Power and PSE&G provide certain technical services for each other generally at cost in compliance with FERC and BPU affiliate rules.
(B)Services provides and bills administrative services to PSE&G and PSEG Power at cost. In addition, PSE&G and PSEG Power have other payables to Services, including amounts related to certain common costs, which Services pays on behalf of each of the operating companies.
(C)PSEG files a consolidated federal income tax return with its affiliated companies. A tax allocation agreement exists between PSEG and each of its affiliated companies. The general operation of these agreements is that the subsidiary company will compute its taxable income on a stand-alone basis. If the result is a net tax liability, such amount shall be paid to PSEG. If there are NOLs and/or tax credits, the subsidiary shall receive payment for the tax savings from PSEG to the extent that PSEG is able to utilize those benefits.
(D)PSE&G and PSEG Power have advanced working capital to Services. The amounts are included in Other Noncurrent Assets on PSE&G’s and PSEG Power’s Consolidated Balance Sheets.
(E)PSEG Power’s short-term loans with PSEG are for working capital and other short-term needs. Interest Income and Interest Expense relating to these short-term funding activities were immaterial.

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE
None.

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ITEM 9A. CONTROLS AND PROCEDURES
ITEM 9A. CONTROLS AND PROCEDURES
Disclosure Controls and Procedures
PSEG, PSE&G and PSEG Power
We have established and maintain disclosure controls and procedures as defined under Rule 13a-15(e) and 15d-15(e) promulgated under the Securities Exchange Act of 1934, as amended (the “Exchange Act”) that are designed to provide reasonable assurance that information required to be disclosed in the reports that are filed or submitted under the Exchange Act is recorded, processed, summarized and reported and is accumulated and communicated to the Chief Executive Officer (CEO) and Chief Financial Officer (CFO) of each respective company, as appropriate, by others within the entities to allow timely decisions regarding required disclosure. We have established a disclosure committee which includes several key management employees and which reports directly to the CFO and CEO of each of PSEG, PSE&G and PSEG Power. The committee monitors and evaluates the effectiveness of these disclosure controls and procedures. The CFO and CEO of each of PSEG, PSE&G and PSEG Power have evaluated the effectiveness of the disclosure controls and procedures and, based on this evaluation, have concluded that disclosure controls and procedures at each respective company were effective at a reasonable assurance level as of the end of the period covered by the report.
Internal Controls
PSEG, PSE&G and PSEG Power
We have conducted assessments of our internal control over financial reporting as of December 31, 2020, as required by Section 404 of the Sarbanes-Oxley Act, using the framework promulgated by the Committee of Sponsoring Organizations of the Treadway Commission, commonly referred to as “COSO.” Managements’ reports on PSEG’s, PSE&G’s and PSEG Power’s internal control over financial reporting are included on pages 183, 184 and 185, respectively. The Independent Registered Public Accounting Firm’s report with respect to the effectiveness of PSEG’s internal control over financial reporting is included on page 186. Management has concluded that internal control over financial reporting is effective as of December 31, 2020.
We continually review our disclosure controls and procedures and make changes, as necessary, to ensure the quality of our financial reporting. There have been no changes in internal control over financial reporting that occurred during the fourth quarter of 2020 that have materially affected, or are reasonably likely to materially affect, each registrant’s internal control over financial reporting.

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ITEM 9B. OTHER INFORMATION
ITEM 9B. OTHER INFORMATION
None.
MANAGEMENT REPORT ON INTERNAL CONTROL OVER
FINANCIAL REPORTING-PSEG
Management of Public Service Enterprise Group Incorporated (PSEG) is responsible for establishing and maintaining effective internal control over financial reporting and for the assessment of the effectiveness of internal control over financial reporting. As defined by the SEC in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and implemented by the company’s management and other personnel, with oversight by the Audit Committee of the Board of Directors to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America (generally accepted accounting principles).
PSEG’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of PSEG’s assets; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of PSEG are being made only in accordance with authorizations of PSEG’s management and directors; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of PSEG’s assets that could have a material effect on the financial statements.
In connection with the preparation of PSEG’s annual financial statements, management of PSEG has undertaken an assessment, which includes the design and operational effectiveness of PSEG’s internal control over financial reporting based on criteria established in the Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, commonly referred to as “COSO”. The COSO framework is based upon five integrated components of control: control environment, risk assessment, control activities, information and communications and ongoing monitoring.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projection of any evaluation of effectiveness to future periods is subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Based on the assessment performed, management has concluded that PSEG’s internal control over financial reporting is effective and provides reasonable assurance regarding the reliability of PSEG’s financial reporting and the preparation of its financial statements as of December 31, 2020 in accordance with generally accepted accounting principles. Further, management has not identified any material weaknesses in internal control over financial reporting as of December 31, 2020.
PSEG’s external auditors, Deloitte & Touche LLP, have audited PSEG’s financial statements for the year ended December 31, 2020 included in this annual report on Form 10-K and, as part of that audit, have issued a report on the effectiveness of PSEG’s internal control over financial reporting, a copy of which is included in this annual report on Form 10-K.
/s/ RALPH IZZO
Chief Executive Officer
/s/ DANIEL J. CREGG
Chief Financial Officer
February 26, 2021
MANAGEMENT REPORT ON INTERNAL CONTROL OVER
FINANCIAL REPORTING-PSE&G
Management of Public Service Electric and Gas Company (PSE&G) is responsible for establishing and maintaining effective internal control over financial reporting and for the assessment of the effectiveness of internal control over financial reporting. As defined by the SEC in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and implemented by the company’s management and other personnel, with oversight by the Audit Committee of the Board of Directors of its parent, Public Service Enterprise Group Incorporated, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America (generally accepted accounting principles).
PSE&G’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of PSE&G’s assets; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of PSE&G are being made only in accordance with authorizations of PSE&G’s management and directors; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of PSE&G’s assets that could have a material effect on the financial statements.
In connection with the preparation of PSE&G’s annual financial statements, management of PSE&G has undertaken an assessment, which includes the design and operational effectiveness of PSE&G’s internal control over financial reporting based on criteria established in the Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, commonly referred to as “COSO”. The COSO framework is based upon five integrated components of control: control environment, risk assessment, control activities, information and communications and ongoing monitoring.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projection of any evaluation of effectiveness to future periods is subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Based on the assessment performed, management has concluded that PSE&G’s internal control over financial reporting is effective and provides reasonable assurance regarding the reliability of PSE&G’s financial reporting and the preparation of its financial statements as of December 31, 2020 in accordance with generally accepted accounting principles. Further, management has not identified any material weaknesses in internal control over financial reporting as of December 31, 2020.
/s/ RALPH IZZO
Chief Executive Officer
/s/ DANIEL J. CREGG
Chief Financial Officer
February 26, 2021
MANAGEMENT REPORT ON INTERNAL CONTROL OVER
FINANCIAL REPORTING-PSEG Power
Management of PSEG Power LLC (PSEG Power) is responsible for establishing and maintaining effective internal control over financial reporting and for the assessment of the effectiveness of internal control over financial reporting. As defined by the SEC in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and implemented by the company’s management and other personnel, with oversight by the Audit Committee of the Board of Directors of its parent, Public Service Enterprise Group Incorporated, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America (generally accepted accounting principles).
PSEG Power’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of PSEG Power’s assets; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of PSEG Power are being made only in accordance with authorizations of PSEG Power’s management and directors; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of PSEG Power’s assets that could have a material effect on the financial statements.
In connection with the preparation of PSEG Power’s annual financial statements, management of PSEG Power has undertaken an assessment, which includes the design and operational effectiveness of PSEG Power’s internal control over financial reporting based on criteria established in the Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, commonly referred to as “COSO”. The COSO framework is based upon five integrated components of control: control environment, risk assessment, control activities, information and communications and ongoing monitoring.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projection of any evaluation of effectiveness to future periods is subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Based on the assessment performed, management has concluded that PSEG Power’s internal control over financial reporting is effective and provides reasonable assurance regarding the reliability of PSEG Power’s financial reporting and the preparation of its financial statements as of December 31, 2020 in accordance with generally accepted accounting principles. Further, management has not identified any material weaknesses in internal control over financial reporting as of December 31, 2020.
/s/ RALPH IZZO
Chief Executive Officer
/s/ DANIEL J. CREGG
Chief Financial Officer
February 26, 2021
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of
Public Service Enterprise Group Incorporated
Opinion on Internal Control over Financial Reporting
We have audited the internal control over financial reporting of Public Service Enterprise Group Incorporated and subsidiaries (the “Company”) as of December 31, 2020, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2020, based on criteria established in Internal Control - Integrated Framework (2013) issued by COSO.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated financial statements and the consolidated financial statement schedule listed in the Index at Item 15(B)(a) as of and for the year ended December 31, 2020 of the Company and our report dated February 26, 2021 expressed an unqualified opinion on those financial statements.
Basis for Opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management Report on Internal Control Over Financial Reporting - PSEG. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ DELOITTE & TOUCHE LLP
Parsippany, New Jersey
February 26, 2021
PART III

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ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE
GOVERNANCE
Executive Officers
PSEG
The information required by Item 10 of Form 10-K with respect to executive officers is set forth in Part I. Information About Our Executive Officers (PSEG).
PSE&G and PSEG Power
Omitted pursuant to conditions set forth in General Instruction I of Form 10-K.
Directors
PSEG
The information required by Item 10 of Form 10-K with respect to (i) present directors of PSEG who are nominees for election as directors at PSEG’s 2021 Annual Meeting of Stockholders, (ii) the director nomination process, and (iii) the composition of the Audit Committee of the Board, is set forth under the headings “Nominees For Director-Biographical Information,” “Overview of Board Nominees-Board Refreshment and Tenure,” and “-Board Membership Selection,” and “Corporate Governance-Board Committees,” respectively, in PSEG’s definitive Proxy Statement for such Annual Meeting of Stockholders, which definitive Proxy Statement is expected to be filed with the U.S. Securities and Exchange Commission (SEC) on or about March 15, 2021 and which information set forth under said heading is incorporated herein by this reference thereto.
PSE&G and PSEG Power
Omitted pursuant to conditions set forth in General Instruction I of Form 10-K.
Standards of Conduct
Our Standards of Conduct (Standards) is a code of ethics applicable to us and our subsidiaries. The Standards are an integral part of our business conduct compliance program and embody our commitment to conduct operations in accordance with the highest legal and ethical standards. The Standards apply to all of our directors and employees (including PSE&G’s, PSEG Power’s, Energy Holdings’ and Services’ respective principal executive officer, principal financial officer, principal accounting officer or Controller and persons performing similar functions). Each such person is responsible for understanding and complying with the Standards. The Standards are posted on our website, https://corporate.pseg.com/aboutpseg/leadershipandgovernance/standardsofconduct. You can get a free copy of the Standards by making an oral or written request directed to:
Vice President, Investor Relations
PSEG Services Corporation
80 Park Plaza, 4th Floor
Newark, NJ 07102
Telephone (973) 430-6565
The Standards establish a set of common expectations for behavior to which each employee must adhere in dealings with investors, customers, fellow employees, competitors, vendors, government officials, the media and all others who may associate their words and actions with us. The Standards have been developed to provide reasonable assurance that, in conducting our business, employees behave ethically and in accordance with the law and do not take advantage of investors, regulators or customers through manipulation, abuse of confidential information or misrepresentation of material facts.
We will post on our website, https://corporate.pseg.com/aboutpseg/leadershipandgovernance/standardsofconduct:
•Any amendment (other than one that is technical, administrative or non-substantive) that we adopt to our Standards; and
•Any grant by us of a waiver from the Standards that applies to any director or executive officer and that relates to any element enumerated by the SEC.
In 2020, we did not grant any waivers to the Standards.
Section 16(a) Beneficial Ownership Reporting Compliance
PSEG
The information required by Item 10 of Form 10-K with respect to compliance with Section 16(a) of the Securities Exchange Act of 1934, as amended, is set forth under the heading “Security Ownership of Directors, Management and Certain Beneficial Owners-Delinquent Section 16(a) Reports” in PSEG’s definitive Proxy Statement for the 2021 Annual Meeting of Stockholders, which definitive Proxy Statement is expected to be filed with the SEC on or about March 15, 2021 and which information set forth under said heading is incorporated herein by this reference thereto.
PSE&G and PSEG Power
Omitted pursuant to conditions set forth in General Instruction I of Form 10-K.

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ITEM 11. EXECUTIVE COMPENSATION
ITEM 11. EXECUTIVE COMPENSATION
PSEG
The information required by Item 11 of Form 10-K is set forth in PSEG’s definitive Proxy Statement for the 2021 Annual Meeting of Stockholders which definitive Proxy Statement is expected to be filed with the SEC on or about March 15, 2021 and such information set forth under such heading is incorporated herein by this reference thereto.
PSE&G and PSEG Power
Omitted pursuant to conditions set forth in General Instruction I of Form 10-K.

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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
PSEG
The information required by Item 12 of Form 10-K with respect to directors, executive officers and certain beneficial owners is set forth under the heading “Security Ownership of Directors, Management and Certain Beneficial Owners” in PSEG’s definitive Proxy Statement for the 2021 Annual Meeting of Stockholders which definitive Proxy Statement is expected to be filed with the SEC on or about March 15, 2021 and such information set forth under such heading is incorporated herein by this reference thereto.
For information relating to securities authorized for issuance under equity compensation plans, see Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.
PSE&G and PSEG Power
Omitted pursuant to conditions set forth in General Instruction I of Form 10-K.

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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND
DIRECTOR INDEPENDENCE
PSEG
The information required by Item 13 of Form 10-K is set forth under the heading “Corporate Governance-Certain Relationships and Related Person Transactions” in PSEG’s definitive Proxy Statement for the 2021 Annual Meeting of Stockholders which definitive Proxy Statement is expected to be filed with the SEC on or about March 15, 2021 and such information set forth under such heading is incorporated herein by this reference thereto.
PSE&G and PSEG Power
Omitted pursuant to conditions set forth in General Instruction I of Form 10-K.

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ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
The information required by Item 14 of Form 10-K is set forth under the heading “Fees Billed by Deloitte for 2020 and 2019” in PSEG’s definitive Proxy Statement for the 2021 Annual Meeting of Stockholders which definitive Proxy Statement is expected to be filed with the SEC on or about March 15, 2021. Such information set forth under such heading is incorporated herein by this reference hereto.
PART IV

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ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
(A) The following Financial Statements are filed as a part of this report:
a.Public Service Enterprise Group Incorporated’s Consolidated Balance Sheets as of December 31, 2020 and 2019 and the related Consolidated Statements of Operations, Comprehensive Income, Cash Flows and Stockholders’ Equity for the three years ended December 31, 2020 on pages 74 through 79.
b.Public Service Electric and Gas Company’s Consolidated Balance Sheets as of December 31, 2020 and 2019 and the related Consolidated Statements of Operations, Comprehensive Income, Cash Flows and Common Stockholder’s Equity for the three years ended December 31, 2020 on pages 80 through 85.
c.PSEG Power LLC’s Consolidated Balance Sheets as of December 31, 2020 and 2019 and the related Consolidated Statements of Operations, Comprehensive Income, Cash Flows and Capitalization and Member’s Equity for the three years ended December 31, 2020 on pages 86 through 91.
(B) The following documents are filed as a part of this report:
a.PSEG’s Financial Statement Schedules:
Schedule II-Valuation and Qualifying Accounts for each of the three years in the period ended December 31, 2020 (page 195).
b.PSE&G’s Financial Statement Schedules:
Schedule II-Valuation and Qualifying Accounts for each of the three years in the period ended December 31, 2020 (page 195).
c.PSEG Power’s Financial Statement Schedules:
Schedule II-Valuation and Qualifying Accounts for each of the three years in the period ended December 31, 2020 (page 195).
Schedules other than those listed above are omitted for the reason that they are not required or are not applicable, or the required information is shown in the consolidated financial statements or notes thereto.
(C) The following documents are filed as part of this report:
LIST OF EXHIBITS:
a. PSEG:
3a
Certificate of Incorporation Public Service Enterprise Group Incorporated(1)
3b
Certificate of Amendment of Certificate of Incorporation of Public Service Enterprise Group Incorporated, effective April 23, 1987(2)
3c
Certificate of Amendment of Certificate of Incorporation of Public Service Enterprise Group Incorporated, effective April 20, 2007(3)
3d
By-Laws of Public Service Enterprise Group Incorporated effective December 15, 2015(4)
4a
Indenture between Public Service Enterprise Group Incorporated and First Union National Bank (U.S. Bank National Association, successor), as Trustee, dated January 1, 1998 providing for Deferrable Interest Subordinated Debentures in Series (relating to Quarterly Preferred Securities)(5)
4b
Indenture between Public Service Enterprise Group Incorporated and U.S. Bank National Association (as successor to First Union National Bank), as Trustee, dated November 1, 1998 providing for Senior Debt Securities(6)
4c
Description of Common Stock(7)
LIST OF EXHIBITS:
10a(1)
Supplemental Executive Retirement Income Plan, amended effective July 1, 2019(8)
10a(2)
Retirement Income Reinstatement Plan for Non-Represented Employees, Amended effective July 1, 2019(9)
10a(3)
2007 Equity Compensation Plan for Outside Directors, amended and restated effective November 19, 2019
10a(4)
Deferred Compensation Plan for Directors, amended effective January 1, 2019(10)
10a(5)
Deferred Compensation Plan for Certain Employees, amended and restated effective January 1, 2019(11)
10a(6)
Senior Management Incentive Compensation Plan(12)
10a(7)
Key Executive Severance Plan of Public Service Enterprise Group Incorporated, amended effective July 1, 2019(13)
10a(8)
Severance Agreement with Ralph Izzo dated December 16, 2008(14)
10a(9)
Stock Plan for Outside Directors, as amended(15)
10a(10)
Compensation Plan for Outside Directors(16)
10a(11)
2004 Long-Term Incentive Plan, amended and restated as of April 16, 2013(17)
10a(12)
Form of Agreement for Advancement of Expenses with Outside Directors(18)
10a(13)
Equity Deferral Plan, effective January 1, 2019(19)
10a(14)
Agreement with Tamara L. Linde dated June 18, 2014(20)
10a(15)
Agreement with Daniel J. Cregg dated September 22, 2015(21)
10a(16)
Clawback Practice, effective February 20, 2018(22)
10a(17)
Agreement with Ralph A. LaRossa dated December 16, 2019(23)
10a(18)
Agreement with David M. Daly dated December 11, 2020
Subsidiaries of the Registrant
Consent of Independent Registered Public Accounting Firm
Certification by Ralph Izzo, pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934 (1934 Act)
31a
Certification by Daniel J. Cregg, pursuant to Rules 13a-14 and 15d-14 of the 1934 Act
Certification by Ralph Izzo, pursuant to Section 1350 of Chapter 63 of Title 18 of the U.S. Code
32a
Certification by Daniel J. Cregg, pursuant to Section 1350 of Chapter 63 of Title 18 of the U.S. Code
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b.
PSE&G
3a(1)
Restated Certificate of Incorporation of PSE&G(24)
3a(2)
Certificate of Amendment of Certificate of Restated Certificate of Incorporation of PSE&G filed February 18, 1987 with the State of New Jersey adopting limitations of liability provisions in accordance with an amendment to New Jersey Business Corporation Act(25)
3a(3)
Certificate of Amendment of Restated Certificate of Incorporation of PSE&G filed June 17, 1992 with the State of New Jersey, establishing the 7.44% Cumulative Preferred Stock ($100 Par) as a series of Preferred Stock(26)
3a(4)
Certificate of Amendment of Restated Certificate of Incorporation of PSE&G filed March 11, 1993 with the State of New Jersey, establishing the 5.97% Cumulative Preferred Stock ($100 Par) as a series of Preferred Stock(27)
3a(5)
Certificate of Amendment of Restated Certificate of Incorporation of PSE&G filed January 27, 1994 with the State of New Jersey, establishing the 6.92% Cumulative Preferred Stock ($100 Par) and the 6.75% Cumulative Preferred Stock ($25 Par) as a series of Preferred Stock(28)
3b(1)
By-Laws of PSE&G as in effect April 17, 2007(29)
LIST OF EXHIBITS:
4a(1) Indenture between PSE&G and Fidelity Union Trust Company (now, Wachovia Bank, National Association), as Trustee, dated August 1, 1924(30), securing First and Refunding Mortgage Bond and Supplemental Indentures between PSE&G and U.S. Bank National Association, successor, as Trustee, supplemental to Exhibit 4a(1), dated as follows:
4a(2) June 1, 1937(31)
4a(3) July 1, 1937(32)
4a(4) June 1, 1991 (No. 1)(33)
4a(5)
August 1, 2004 (No. 4)(34)
4a(6)
April 1, 2007(35)
4a(7)
November 1, 2009(36)
4a(8)
May 1, 2012(37)
4a(9)
May 1, 2013(38)
4a(10)
August 1, 2014(39)
4a(11)
May 1, 2015(40)
4a(12)
September 1, 2016(41)
4a(13)
April 1, 2018(42)
4a(14)
December 1, 2019(43)
4b
Description of the First and Refunding Mortgage Bonds(44)
4c Indenture of Trust between PSE&G and Chase Manhattan Bank (National Association) (The Bank of New York Mellon, successor), as Trustee, providing for Secured Medium-Term Notes dated July 1, 1993(45)
4d
Indenture dated as of December 1, 2000 between Public Service Electric and Gas Company and First Union National Bank (U.S. Bank National Association, successor), as Trustee, providing for Senior Debt Securities(46)
10a(1)
Supplemental Executive Retirement Income Plan, amended effective July 1, 2019(8)
10a(2)
Retirement Income Reinstatement Plan for Non-Represented Employees, Amended effective July 1, 2019(9)
10a(3)
2007 Equity Compensation Plan for Outside Directors, amended and restated effective November 19, 2019
10a(4)
Deferred Compensation Plan for Directors, amended effective January 1, 2019(10)
10a(5)
Deferred Compensation Plan for Certain Employees, amended and restated effective January 1, 2019(11)
10a(6)
Senior Management Incentive Compensation Plan(12)
10a(7)
Key Executive Severance Plan of Public Service Enterprise Group Incorporated, amended effective July 1, 2019(13)
10a(8)
Severance Agreement with Ralph Izzo dated December 16, 2008(14)
10a(9)
Stock Plan for Outside Directors, as amended(15)
10a(10)
Compensation Plan for Outside Directors(16)
10a(11)
2004 Long-Term Incentive Plan, amended and restated as of April 16, 2013(17)
10a(12)
Form of Agreement for Advancement of Expenses with Outside Directors(47)
10a(13)
Equity Deferral Plan, effective January 1, 2019(19)
10a(14)
Agreement with Tamara L. Linde dated June 18, 2014(20)
10a(15)
Agreement with Daniel J. Cregg dated September 22, 2015(21)
10a(16)
Clawback Practice, effective February 20, 2018(22)
10a(17)
Agreement with David M. Daly dated December 11, 2020
23a
Consent of Independent Registered Public Accounting Firm
31b
Certification by Ralph Izzo, pursuant to Rules 13a-14 and 15d-14 of the 1934 Act
31c
Certification by Daniel J. Cregg, pursuant to Rules 13a-14 and 15d-14 of the 1934 Act
32b
Certification by Ralph Izzo, pursuant to Section 1350 of Chapter 63 of Title 18 of the U.S. Code
32c
Certification by Daniel J. Cregg, pursuant to Section 1350 of Chapter 63 of Title 18 of the U.S. Code
LIST OF EXHIBITS:
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c. PSEG Power:
3a
Certificate of Formation of PSEG Power LLC(48)
3b
PSEG Power LLC Limited Liability Company Agreement(49)
4a
Indenture dated April 16, 2001 between and among PSEG Power, PSEG Fossil, PSEG Nuclear, PSEG Energy Resources & Trade and The Bank of New York Mellon and form of Subsidiary Guaranty included therein(50)
4b
First Supplemental Indenture, dated as of March 13, 2002(51)
4c
Description of the Senior Notes(52)
10a(1)
Supplemental Executive Retirement Income Plan, amended effective July 1, 2019(8)
10a(2)
Retirement Income Reinstatement Plan for Non-Represented Employees, Amended effective July 1, 2019(9)
10a(3)
Deferred Compensation Plan for Certain Employees, amended and restated effective January 1, 2019(11)
10a(4)
Senior Management Incentive Compensation Plan(12)
10a(5)
Key Executive Severance Plan of Public Service Enterprise Group Incorporated, amended effective July 1, 2019(13)
10a(6)
Severance Agreement with Ralph Izzo dated December 16, 2008(14)
10a(7)
2004 Long-Term Incentive Plan, amended and restated as of April 16, 2013(17)
10a(8)
Equity Deferral Plan, effective January 1, 2019(19)
10a(9)
Agreement with Tamara L. Linde dated June 18, 2014(20)
10a(10)
Agreement with Daniel J. Cregg dated September 22, 2015(21)
10a(11)
Clawback Practice, effective February 20, 2018(22)
10a(12)
Agreement with Ralph A. LaRossa dated December 16, 2019(23)
Guaranteed Securities
31d
Certification by Ralph Izzo, pursuant to Rules 13a-14 and 15d-14 of the 1934 Act
31e
Certification by Daniel J. Cregg, pursuant to Rules 13a-14 and 15d-14 of the 1934 Act
32d
Certification by Ralph Izzo, pursuant to Section 1350 of Chapter 63 of Title 18 of the U.S. Code
32e
Certification by Daniel J. Cregg, pursuant to Section 1350 of Chapter 63 of Title 18 of the U.S. Code
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(1)Filed as Exhibit 3.1a with Quarterly Report on Form 10-Q for the quarter ended March 31, 2007, File No. 001-09120, on May 4, 2007 and incorporated herein by this reference.
(2)Filed as Exhibit 3.1b with Quarterly Report on Form 10-Q for the quarter ended March 31, 2007, File No. 001-09120, on May 4, 2007 and incorporated herein by this reference.
(3)Filed as Exhibit 3.1c with Quarterly Report on Form 10-Q for the quarter ended March 31, 2007, File No. 001-09120, on May 4, 2007 and incorporated herein by this reference.
(4)Filed as Exhibit 99.1 with Current Report on Form 8-K, File No. 001-09120, on December 16, 2015 and incorporated herein by this reference.
(5)Filed as Exhibit 4(f) with Quarterly Report on Form 10-Q for the quarter ended March 31, 1998, File No. 001-09120, on May 13, 1998 and incorporated herein by this reference.
(6)Filed as Exhibit 4(f) with Annual Report on Form 10-K for the year ended December 31, 1998, File No. 001-09120, on February 23, 1999 and incorporated herein by this reference
(7)Filed as Exhibit 4c for PSEG with Annual Report on Form 10-K for the year ended December 31, 2019. File No. 001-09120, on February 26,2020 and incorporated herein by this reference.
(8)Filed as Exhibit 10.1 with Quarterly Report on Form 10-Q for the quarter ended September 30, 2019, File No. 001-09120, on October 31, 2019 and incorporated herein by this reference.
(9)Filed as Exhibit 10.2 with Quarterly Report on Form 10-Q for the quarter ended September 30, 2019, File No. 001-09120, on October 31, 2019 and incorporated herein by this reference.
(10)Filed as Exhibit 10a(4) with Annual Report on Form 10-K for the year ended December 31, 2018, File No. 001-09120 on February 27, 2019 and incorporated herein by this reference.
(11)Filed as Exhibit 10a(5) with Annual Report on Form 10-K for the year ended December 31, 2018, File No. 001-09120 on February 27, 2019 and incorporated herein by this reference.
(12)Filed as Exhibit 10a(11) with Annual Report on Form 10-K for the year ended December 31, 2008, File No. 001-09120, on February 26, 2009 and incorporated herein by this reference.
(13)Filed as Exhibit 10.3 with Quarterly Report on Form 10-Q for the quarter ended September 30, 2019, File No. 001-09120 on October 31, 2019 and incorporated herein by this reference.
(14)Filed as Exhibit 99 with Current Report on Form 8-K, File Nos. 001-09120, 000-49614 and 001-00973, on December 22, 2008 and incorporated herein by this reference.
(15)Filed as Exhibit 10a(17) with Annual Report on Form 10-K for the year ended December 31, 2002, File No. 001-09120, on February 26, 2003 and incorporated herein by this reference.
(16)Filed as Exhibit 10a(20) with Annual Report on Form 10-K for the year ended December 31, 2002, File No. 001-09120, on February 26, 2003 and incorporated herein by this reference.
(17)Filed as Exhibit 10 with Quarterly Report on Form 10-Q for the quarter ended March 31, 2013, File No. 001-09120, on May 1, 2013 and incorporated herein by this reference.
(18)Filed as Exhibit 10.1 with Current Report on Form 8-K, File No. 001-09120, on February 19, 2009 and incorporated herein by this reference.
(19)Filed as Exhibit 10a(15) with Annual Report on Form 10-K for the year ended December 31, 2018, File No. 001-09120 on February 27, 2019 and incorporated herein by this reference.
(20)Filed as Exhibit 10a with Annual Report on Form 10-K for the year ended December 31, 2014, File No. 001-09120, on February 26, 2015, and incorporated herein by this reference.
(21)Filed as Exhibit 10 with Quarterly Report on Form 10-Q for the quarter ended September 30, 2015, File No. 001-09120, on October 30, 2015, and incorporated herein by this reference.
(22)Filed as Exhibit 10a(20) with Annual Report on Form 10-K for the year ended December 31, 2017, File No. 001-09120 on February 26, 2018 and incorporated herein by this reference.
(23)Filed as Exhibit 10a(19) with Annual Report on Form 10-K for the year ended December 31, 2019, File No. 001-09120, on February 26, 2020 and incorporated herein by this reference.
(24)Filed as Exhibit 3a(1) on Form 8-A, File No. 001-00973, on February 4, 1994 and incorporated herein by this reference.
(25)Filed as Exhibit 3a(2) on Form 8-A, File No. 001-00973, on February 4, 1994 and incorporated herein by this reference.
(26)Filed as Exhibit 3a(3) on Form 8-A, File No. 001-00973, on February 4, 1994 and incorporated herein by this reference.
(27)Filed as Exhibit 3a(4) on Form 8-A, File No. 001-00973, on February 4, 1994 and incorporated herein by this reference.
(28)Filed as Exhibit 3a(5) on Form 8-A, File No. 001-00973, on February 4, 1994 and incorporated herein by this reference.
(29)Filed as Exhibit 3.3 with Quarterly Report on Form 10-Q for the quarter ended March 31, 2007, File No. 001-00973, on May 4, 2007 and incorporated herein by this reference.
(30)Filed as Exhibit 4b(1) with Annual Report on Form 10-K for the year ended December 31, 1980, File No. 001-00973, on February 18, 1981 and incorporated herein by this reference.
(31)Filed as Exhibit 4b(3) with Annual Report on Form 10-K for the year ended December 31, 1980, File No. 001-00973, on February 18, 1981 and incorporated herein by this reference.
(32)Filed as Exhibit 4b(4) with Annual Report on Form 10-K for the year ended December 31, 1980, File No. 001-00973, on February 18, 1981 and incorporated herein by this reference.
(33)Filed as Exhibit 4(i) on Form 8-A, File No. 001-00973, on June 1, 1991 and incorporated herein by this reference.
(34)Filed as Exhibit 4a(28) with Annual Report on Form 10-K for the year ended December 31, 2004, File No. 001-00973, on March 1, 2005 and incorporated herein by this reference.
(35)Filed as Exhibit 4a(28) with Annual Report on Form 10-K for the year ended December 31, 2007, File No. 001-00973, on February 28, 2008 and incorporated herein by this reference.
(36)Filed as Exhibit 4a(30) with Annual Report on Form 10-K for the year ended December 31, 2009, File No. 001-00973, on February 25, 2010 and incorporated herein by this reference.
(37)Filed as Exhibit 4a(32) with Annual Report on Form 10-K for the year ended December 31, 2012, File No. 001-00973, on February 26, 2013, and incorporated herein by this reference.
(38)Filed as Exhibit 4 with Quarterly Report on Form 10-Q for the quarter ended June 30, 2013, File No. 001-00973, on July 30, 2013, and incorporated herein by this reference.
(39)Filed as Exhibit 4a(22) with Quarterly Report on Form 10-Q for the quarter ended September 30, 2014, File No. 001-09120, on October 30, 2014 and incorporated herein by this reference.
(40)Filed as Exhibit 4a(23) with Quarterly Report on Form 10-Q for the quarter ended June 30, 2015, File No. 001-09120, on July 31, 2015 and incorporated herein by this reference.
(41)Filed as Exhibit 4a(14) with Annual Report on Form 10-K for the year ended December 31, 2016, File No. 001-00973, on February 27, 2017 and incorporated herein by this reference.
(42)Filed as Exhibit 4a(15) with Quarterly Report on Form 10-Q for the quarter ended March 31, 2018, File No. 001-00973, on April 30, 2018 and incorporated herein by this reference.
(43)Filed as Exhibit 4a(15) with Annual Report on Form 10-K for the year ended December 31, 2019, File No. 001-09120, on February 26, 2020 and incorporated herein by this reference.
(44)Filed as Exhibit 4b with Annual Report on Form 10-K for the year ended December 31, 2019, File No. 001-09120, on February 26, 2020 and incorporated herein by the reference.
(45)Filed as Exhibit 4 with Current Report on Form 8-K, File No. 001-00973, on December 1, 1993 and incorporated herein by this reference.
(46)Filed as Exhibit 4-6 to Registration Statement on Form S-3, File No. 333-76020, filed on December 27, 2001 and incorporated herein by this reference.
(47)Filed as Exhibit 10.2 with Current Report on Form 8-K, File No. 001-00973, on February 19, 2009 and incorporated herein by this reference.
(48)Filed as Exhibit 3.1 to Registration Statement on Form S-4, No. 333-69228, filed on September 10, 2001 and incorporated herein by this reference.
(49)Filed as Exhibit 3.2 to Registration Statement on Form S-4, No. 333-69228, filed on September 10, 2001 and incorporated herein by this reference.
(50)Filed as Exhibit 4.1 to Registration Statement on Form S-4, No. 333-69228, filed on September 10, 2001 and incorporated herein by this reference.
(51)Filed as Exhibit 4.7 with Quarterly Report on Form 10-Q for the quarter ended March 31, 2002, File No. 000-49614, on May 15, 2002 and incorporated herein by this reference.
(52)Filed as Exhibit 4c for PSEG Power with Annual Report on Form 10-K for the year ended December 31, 2019, File No. 001-09120, on February 26, 2020 and incorporated herein by this reference.
Schedule II-Valuation and Qualifying Accounts Years Ended December 31, 2020-December 31, 2018
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
Column A Column B Column C Additions Column D Column E
Description Balance at
Beginning of
Period Charged to
cost and
expenses Charged to
other
accounts-
describe Deductions-
describe Balance at
End of
Period
Millions
Allowance for Credit Losses $ 68 (D) $ 175 (A) $ - $ 37 (B) $ 206
Materials and Supplies Valuation Reserve 11 1 - 2 (C) 10
Allowance for Credit Losses $ 63 $ 87 (A) $ - $ 90 (B) $ 60
Materials and Supplies Valuation Reserve 9 3 - 1 (C) 11
Allowance for Credit Losses $ 59 $ 91 (A) $ - $ 87 (B) $ 63
Materials and Supplies Valuation Reserve 7 4 - 2 (C) 9
(A)For a discussion of bad debt recoveries, see Note 1. Organization, Basis of Presentation and Summary of Significant Accounting Policies.
(B)Accounts Receivable written off.
(C)Reduce reserve to appropriate level and to remove obsolete inventory.
(D)Includes $8 million due to the adoption of ASU 2016-13.
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
Column A Column B Column C Additions Column D Column E
Description Balance at
Beginning
of Period Charged to
cost and
expenses Charged to
other
accounts-
describe Deductions-
describe Balance at
End of
Period
Millions
Allowance for Credit Losses $ 68 (C) $ 175 (A) $ - $ 37 (B) $ 206
Materials and Supplies Valuation Reserve 2 - - - 2
Allowance for Credit Losses
$ 63 $ 87 (A) $ - $ 90 (B) $ 60
Materials and Supplies Valuation Reserve 2 - - - 2
Allowance for Credit Losses $ 59 $ 91 (A) $ - $ 87 (B) $ 63
Materials and Supplies Valuation Reserve - 2 - - 2
(A)For a discussion of bad debt recoveries, see Note 1. Organization, Basis of Presentation and Summary of Significant Accounting Policies.
(B)Accounts Receivable written off.
(C)Includes $8 million due to the adoption of ASU 2016-13.
PSEG POWER LLC
Column A Column B Column C Additions Column D Column E
Description Balance at
Beginning
of Period Charged to
cost and
expenses Charged to
other
accounts-
describe Deductions-
describe Balance at
End of
Period
Millions
Materials and Supplies Valuation Reserve $ 9 $ 1 $ - $ 2 (A) $ 8
Materials and Supplies Valuation Reserve $ 7 $ 3 $ - $ 1 (A) $ 9
Materials and Supplies Valuation Reserve $ 7 $ 2 $ - $ 2 (A) $ 7
(A)Reduce reserve to appropriate level and to remove obsolete inventory.