FILING FORMAT
This combined Annual Report on Form 10-K 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 relating to any individual company is filed by such company on its own behalf. PSE&G and PSEG Power are each only responsible for information about itself and its subsidiaries.
Discussions throughout the document refer to PSEG and its direct operating subsidiaries, PSE&G and PSEG Power. Depending on the context of each section, references to “we,” “us,” and “our” relate to PSEG or to the specific company or companies being discussed.
WHERE TO FIND MORE INFORMATION
We file annual, quarterly and current reports, proxy statements and other information with the SEC. You may obtain our filed documents from commercial document retrieval services, the SEC’s internet website at www.sec.gov or our website at investor.pseg.com. Information on our website should not be deemed incorporated into or as a part of this report. Our Common Stock is listed on the New York Stock Exchange under the trading symbol PEG. You can obtain information about us at the offices of the New York Stock Exchange, Inc., 11 Wall Street, New York, New York 10005.
PART I
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. | |||||||||||||
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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;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 |
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.
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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 powerpower 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 and demand response 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 $2.8$2.5 billion for transmission in 2020-20222021-2023 as disclosed in Item 7. MD&A—Capital Requirements.
Distribution
PSE&G distributes gaselectricity and electricitynatural 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, seeItem 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 2019:2020:
| % of 2019 Sales | ||||||
| Customer Type | Electric | Gas | ||||
| Commercial | 58% | 38% | ||||
| Residential | 33% | 58% | ||||
| Industrial | 9% | 4% | ||||
| Total | 100% | 100% | ||||
| % 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 2015,2016, with electric and gas loads changing as illustrated below:
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| Electric and Gas Distribution Statistics | |||||||||||
| December 31, 2019 | |||||||||||
Number of Customers | Electric Sales and Firm Gas Sales (A) | Historical Annual Load Growth 2015-2019 | |||||||||
| Electric | 2.3 | Million | 40,684 | Gigawatt hours (GWh) | —% | ||||||
| Gas | 1.9 | Million | 2,589 | Million Therms | (0.3)% | ||||||
| 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 were essentially flat with increasesdeclined due to growth in the numbereconomic impact of customers and improved economic conditions offset bythe ongoing coronavirus pandemic (COVID-19) on commercial usage, greater conservation, and more energy efficient appliances.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 slightly as a result of warmer weather in 2019 mostly2020 and lower commercial customer usage due to the pandemic, partially offset by growthan increase in residential sales due to the number of customerspandemic, 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 and capacity 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 39%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. See Item 8. Note 7. Regulatory Assets and Liabilities. 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.
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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 seekhave 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 profitrevenue 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 |
•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 Contentsthe 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 46%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 in the Mid-Atlantic and Northeast regions which comprises the vast majority of PSEG Power’s operations and financial performance.
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How PSEG Power’s Generation Operates
Nearly all of our generation capacity consists of nuclear and fossil generation that 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.
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.
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Fuel Supply
•Nuclear Fuel Supply—We have long-term contracts for nuclear fuel. These contracts provide for: • |
purchase of uranium (concentrates and uranium hexafluoride),
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•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.
as an alternate fuel by several load following and peaking units that have a dual-fuel capability. Oil |
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 20192020 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. |
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. One of the reasons for the lower natural gas prices is greater supply from more recently-developed sources, such as shale gas, much of which is produced in states adjacent to New Jersey (e.g. Pennsylvania). 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. Currently, there is sufficient capacity in the markets in which we operate. However, in certain areasSee Item 7. MD&A—Executive Overview of these markets, there are transmission system transfer limitations which raise concerns about reliability2020 and create a more acute need for capacity.Future Outlook—Wholesale Power Market Design.
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In PJM and ISO-NE, where we operate most of our generation, the market design for capacity payments provides for a structured, forward-looking, transparent capacity pricing mechanism. This is through the Reliability Pricing Model (RPM) in PJM and the Forward Capacity Market (FCM) in ISO-NE. These mechanisms provide greater transparency regarding the value of capacity and provide a pricing signal to prospective investors in new generating facilities to encourage expansion of capacity to meet future market demands. 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 mechanismand New England capacity through May 2026 for BH5Bridgeport Harbor Unit 5 and May 20232024 for New Haven through the RPM and FCM pricing mechanisms, respectively.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 hedgehave hedged our output are: (1) sales at PJM West or other nodes within PJM corresponding to our generation portfolio and (2) BGS and similarphysical 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. The BGS-RSCP contract, a full-requirements contract that includes energy and capacity, ancillary and other services, is awarded for three-year periods through an auction process managed by the BPU. The volume of BGS contracts and the mix of electric utilities that our generation operations serve will vary from year to year. Pricing for the BGS contracts, including a capacity component, for recent and future periods by purchasing utility is as follows:
| Load Zone ($/MWh) | 2017-2020 | 2018-2021 | 2019-2022 | 2020-2023 | ||||||
| PSE&G | $90.78 | $91.77 | $98.04 | $102.16 | ||||||
| Jersey Central Power & Light Company (JCP&L) | $69.08 | $73.11 | $77.15 | $72.43 | ||||||
| Atlantic City Electric Company | $75.49 | $81.23 | $87.40 | $82.69 | ||||||
| Rockland Electric Company | $80.50 | $85.94 | $88.03 | $82.42 | ||||||
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. The BGS auction, for example, results in a contract that provides for the supplier to serve a percentage of the default load of a New Jersey EDC, that is, the load that remains after some customers have chosen to be served directly either by third-party suppliers or through municipal aggregation. The amount of power supplied through the BGS auction varies based on the level of the EDC’s default load, which is affected by the number of customers who are served by third-party suppliers, as well as by other factors such as weather and the economy.
| Base Load Generation | 2020 | 2021 | 2022 | |||||
| Generation Sales | 100% | 80%-85% | 30%-35% | |||||
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 20202021 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% | |||||||||||||||||||||||
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Energy Holdings
Lease Investments
Energy Holdings primarily owns and manages a portfolio of domestic lease investments comprised principally of energy-related leveraged leases.investments. See Item 8. Note 10. Financing Receivables for additional information.
Offshore Wind
In June 2019, the BPU selectedDecember 2020, PSEG entered into a definitive agreement with Ørsted US Offshore Wind’s Ocean Wind project as the winning bid in New Jersey’s initial
LIPA OperatingOperations Services Agreement (OSA)
In accordance with a twelve year Amended and Restated OSAOperations 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 transmission and distributionT&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
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•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 (DR) 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.
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, 2019, we had 12,9922020, PSEG employed 12,788 full-time employees, within our subsidiaries, including 8,001of which 61% are covered underby collective bargaining agreements expiringagreements. 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.
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Talent Management and Engagement
PSEG is committed to attracting, developing and retaining a robust talent pipeline, from 2021our 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 2023everyday 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 eight unions. We believe we maintain satisfactory relationshipsunion leadership and the 7,786 employees represented by unions in our workforce. Our strong relationship with our employees.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.
| Employees as of December 31, 2019 | ||||||||||||||
| PSE&G | PSEG Power | PSEG LI | Services | |||||||||||
| Non-Union | 1,923 | 993 | 995 | 1,080 | ||||||||||
| Union | 5,207 | 1,040 | 1,507 | 247 | ||||||||||
| Total Employees | 7,130 | 2,033 | 2,502 | 1,327 | ||||||||||
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 FERC and 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
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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. The followingCertain PSEG companies are public utilities and currently have MBR Authority: PSE&G, PSEG Energy Resources & Trade (ER&T), PSEG Fossil, PSEG Fossil Sewaren Urban Renewal LLC, PSEG Nuclear, PSEG Power Connecticut, PSEG New Haven, PSEG Energy Solutions, PSEG Keys Energy Center LLC, Pavant Solar II LLC, San Isabel Solar LLC and Bison Solar LLC. FERC requires that holders of MBR Authority file an update every three years demonstrating that they continue to lack market power and/or that their market power has been sufficiently mitigated and report in the interim to FERC any material change in facts from those FERC relied on in granting 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 nonperformancenon-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 them.PJM’s final compliance filing. We will continue to participate in this process before FERC.proceeding.
In March 2019, PJM filed aMay 2020, FERC issued an order approving PJM’s proposal under section 206 of the FPA 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. If placed into effect, theseThese reforms are expected to improve energy and reserve prices by ensuring that when operators commit resources to ensure reliability, the commitments are reflectedwill be implemented in market clearing prices. However, these reforms could result in lower capacity payments. There is no timeline for this type of filing and therefore we cannot predict when FERC will act on the filing or the outcome of this matter.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, and Delaware are members of RGGI and other states, such as Virginia and Pennsylvania continuecontinues to investigate joining. 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. The process is expected to continue through 2020 2021and 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
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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. The exemptions
PSEG Power’s New Jersey nuclear plants that receive ZEC payments will be subject to the new MOPR. Resources that are limited to: (i) existing self-supply generation resources; (ii) existing DR, energy efficiency and storage; (iii) existing renewable resources participating in renewable portfolio standard (RPS) programs; and (iv) a competitive exemption for new and existing resources that agree to forgo subsidies. The FERC order also retained a unit-specific exemptionsubject 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 would allow entitiescan 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 demonstratebecome 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 monitor that they should be ablewould impact our ability to bid at a level below the generic MOPR offer floor. PSEG cannot at this time estimate the impactclear any of the MOPR on resources that receive out-of-market payments or the markets generally. The rule also provides that federal subsidies would not trigger the MOPR.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 Fixed Resource Requirement (FRR)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.
ISO-NE—ISO-NE’s market for installed capacity in New England provides fixed capacity payments for generators, imports and DR.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—In March 2019,From time to time, various matters are pending before FERC issued a Noticerelating to, among other things, transmission planning, reliability standards and transmission rates and returns, including incentives. Depending on their outcome, any of Inquiry (NOI) seeking comment on improvements to FERC’s electric transmission incentives policy to ensure that it appropriately encourages the developmentthese matters could materially impact our results of the infrastructure needed to ensure grid reliabilityoperations and reduce congestion to lower the cost of power for consumers. The NOI is intended to examine whether existing incentives, such as the 50 basis point adder for RTO membership, should continue to be granted and whether new incentives should be established. The NOI includes the consideration of incentives for economic efficiency and reliability benefits, RTO membership, improvements to existing transmission facilities, consideration of the costs and benefits of projects in awarding incentives, and determination of whether to review incentive applications on a case-specific or standardized basis.financial condition.
In November 2019, FERC issued an order establishing a new ROE policy for reviewing existing transmission ROEs. FERC applied the new policy to two complaints filed against the Midcontinent Independent System Operator (MISO) transmission owners. The new methodology uses the Discounted Cash Flowdiscounted cash flow (DCF) model and Capital Asset Pricingcapital asset pricing model (CAPM) to determine if an existing base ROE is unjust and unreasonable and, if so, what replacement ROE is appropriate. Based on the new methodology, FERC found that the MISO transmission owners’ ROE was unjust and unreasonable and directed that the ROE be lowered. PSE&G joined the PJM Transmission Owners in requesting rehearing of FERC’s order on the grounds that the new methodology is flawed. Other 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 Ownerstransmission owners and utilities in other jurisdictions.
In parallel to these proceedings, and in light of declining interest rates and other market conditions,addition, over the past few years, several companies have negotiated settlements that have resulted in reduced ROEs.
We continue to analyzeare engaged in settlement discussions with the potential impactBPU Staff and the New Jersey Division of these methodologies andRate Counsel (New Jersey Rate
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Counsel) about the level of PSE&G’s base transmission ROE; however, we cannot predict the outcome of ongoing ROE proceedings.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 will beare 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 couldcan decide or be required to build additional redundancy into their systems. This standard will supplementsupplements the Critical Infrastructure Protection (CIP) standards that are already in place and that establish physical and cybersecurity protections for critical systems. We are taking steps to meet these obligations. 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. In October 2018, FERC approved the supply chain management standard effective Julyin October 2018, with an implementation date of October 1, 2020. We are currently planning for compliancehave documented procedures and implemented new processes to comply with the new standards which have imposed additional obligations and costs.these standards.
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 security and protection of 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 also 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 as a result of these ongoing reviews.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 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 demand response and energy efficiency programs is also regulated by the BPU, as the terms
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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. The EMP further anticipates increased involvement by the BPU in transmission ROE and cost allocation proceedings at FERC to protect New Jersey ratepayers. 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 addressing natural gas supply issues 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—InJuly 2019,2020, the state’sState’s EDCs filed their annual proposal for the conduct of the February 20202021 BGS auction covering electric supply for energy years 20212022 through 2023.2024. In the course of the proceeding, among other issues, the EDCs indicated their concerns regarding the impact on the BGS auction from the delay of PJM’s 2022/23 capacity auction due to certain legal concerns. In November 2019,prior years, the BPU issued its Decision and Order (BGS Order) authorizing the conduct of the February 2020 BGS auction (which was conducted from late January through early February 2020). In its BGS Order, the BPU accepted the EDCs’ proposal for the establishment of a capacity proxy price for the third year of the February 2020 BGS auction, at a level based on the average of past PJM capacity auction prices, which is intended to eliminate some uncertaintysuppliers expressed concerns regarding the capacity price for the third year of the auction. The BGS Order also recognized the concern expressed by suppliers regarding the transmission costs incurred by BGS participants beingthat are collected from customers but not paid to the BGS suppliers due to several unresolved proceedings at FERC,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 directed Board Staff(b) amend existing BGS contracts to work withtransfer responsibility for transmission-through the parties priortransfer of specific PJM billing line items-from the BGS supplier to the filing ofEDCs. 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 proposals.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 New Jersey’sthe Clean Energy Act, of 2018, the BPU was required to undertake several initiatives in connection with New Jersey’s solar energy market.
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The Clean Energy Act also requires thatrequired the BPU to close the existing SREC program to new applications by no later thanat the earlier of June 1, 2021 upon attainingor the date at which 5.1% of New Jersey retail electric sales are derived from solar; providesolar. 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 an orderly transitioneach MWh of solar production. The New Jersey EDCs, including PSE&G, are required to purchase, using the services of a new SREC program, and createTREC administrator, TRECs from solar projects at rates set by the new program.BPU. PSE&G filed for rate recovery of these costs in April 2020. In December 2019,August 2020, the BPU issued an order (Transition Order) approving the establishment and general structure of a Transition Incentive (TI) Program, intended to serve as a bridge between the SREC program and the to-be-established successor program. There are significant differences between the existing SREC program and the TI program, particularly with respect to pricing of the certificates, the entities obligated to acquire SRECs, and RPS compliance.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 TItransition 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 and our customers’ information and our 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:
•Cybersecurity Council, Council—which is comprised of members of senior management, meets regularly to discuss emerging cybersecurity issues;issues and maintenance of a corporate cybersecurity scorecard that sets annual improvement targets to approximately 30 metrics; and publicationmeasure performance of security practices.key risk indicators. The Cybersecurity Council ensures that senior management, and ultimately, the Board, is informed of allgiven the information required to exercise proper oversight over cybersecurity risks and that escalation procedures are followed to promptly inform seniorfollowed.
•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 and the Board of significant cybersecurity incidents and risks.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 cybercybersecurity 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
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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 CIPCritical 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 thesethe supply chain risk management standardsstandard in October 2018, with an implementation date of JulyOctober 1, 2020. We are taking stepshave documented procedures and implemented new processes to meet these additional obligations. Compliancecomply with these new standards would be expected to impose additional costs.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 New York’s governor signed into lawbecame effective in July 2019 and will become effective on March 21, 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 (CAA) 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 CAAClean 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
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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, theEPA 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 bythe 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 CAAClean Air Act—In June 2019, the EPA issued its final Affordable Clean Energy (ACE)ACE rule as a replacement for the repealed Clean Power Plan, a greenhouse gasGHG 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 Rulerule 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 estimatepredict the impactoutcome of this actionmatter or estimate its impact on our business or results of operations.
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. These rules make allowances available through a regional auction whereby generators may acquire allowancesGenerating plants operating in RGGI states that are each equalemit CO2 will have to one ton of CO2 emissions. Generators are required to submit an allowanceprocure credits for each ton emitted over a three-year period. Allowances are available through the auction or secondary markets.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 greenhouse gas (GHG)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 auction proceedscredits will be allocated among the New Jersey Economic Development Authority (NJEDA), the BPU and the NJDEP. TheIn April 2020, the state has issued a draftfinal three-year Strategic Funding Plan and has announced that a final plan is expecteddetermines how quarterly RGGI credits are to be issued prior to the allocation of proceeds in April 2020 from the 2020 auction.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.
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
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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 has structuredrequires that the rule soNPDES permits be renewed every five years and that each state Permitting Director will continue to considermanage renewal permits for existingits respective power generation facilities on a case by case basis, based on studies related to impingement mortality and entrainment and submitbasis. The NJDEP manages the results with their permit applications to be conducted by the facilities seeking renewal permits.
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 | 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 | 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 | 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 | President - PSE&G | October 2017 to present | ||||||||||||||||||
| President and COO of PSEG Utilities and Clean Energy Ventures - Services; President - PSE&G | January 2020 to | |||||||||||||||||||
| COB - PSEG Long Island LLC | October 2017 to | |||||||||||||||||||
| October 2017 to December 2019 | ||||||||||||||||||||
| President and COO - PSEG Long Island LLC | October 2013 to October 2017 | |||||||||||||||||||
| Derek M. DiRisio | President - Services | August 2014 to present | ||||||||||||||||||
| Tamara L. Linde | 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 | 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
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.
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.
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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;
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•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 oversighton 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;
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•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
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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 thedevelopment, construction and operation of the project, as well as other risks and uncertainties inherent in joint venture arrangements;
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•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
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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.
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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.
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 asset valuesoutput 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 nuclear decommissioning trust (NDT) Fundplants 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 defined benefit plan trust funds. Market performance
•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 other factorscorrecting 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 decrease the value of trust assetsbe substantial and could result in the need for significant additional funding.
In addition, as market prices for energy and financial position.
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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. In particular, PSE&G is currently seeking approval for a number of investment programs fromIf the BPU including our proposed CEF program, a six-year estimated $3.5 billion investment program covering energy efficiency (CEF-EE), energy cloud (CEF-EC) and electric vehicles and energy storage (CEF EV/ES) programs. The BPU is reviewing the CEF-EE program concurrently with its efforts related to implementing provisions of the Clean Energy Act related to energy efficiency. Additionally, New Jersey released its EMP in January 2020, which is supportive of energy efficiency but gives the BPU discretion in implementation between state-and utility-operated programs. In February 2020, PSE&G reached an agreement with parties in the CEF-EE matter which was approved by the BPU to extend the timeline for review of the CEF-EE filing through September 2020. In addition, the BPU has circulated to the parties procedural schedules for the CEF-EC, CEF-EV and CEF-ES programs. If these programs and other 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
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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 November 2019 and 2020, FERC issued an order establishinga series of orders that establish a new ROE policy for reviewing existing transmission ROEs. FERC appliedThe methodology uses the new policyDCF model, the CAPM and the risk premium model to two complaints filed against the MISO transmission owners and found these ROEs to bedetermine if an existing base ROE is unjust and unreasonable. Otherunreasonable and, if so, what replacement ROE is appropriate. In addition, ROE complaints have been pending before FERC, regarding the ISO New England Inc. Transmission Ownerstransmission owners and utilities in other jurisdictions. Over the past few years, several companies have negotiated settlements that have resulted in reduced ROEs.
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 we are notOrder 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 of any of these complaints, they could set a precedent for FERC-regulated transmission owners, such asto recovery by PSE&G. Changes to FERC’s transmission ROE policy and challenges by FERC, the BPU or other constituencies to our&G under its rate base, transmission ROE could limit our ability to obtain fair or timely recovery of all our costs, including a return of or on our investments in rates, which could have a material adverse impact on our business, financial condition and results of operations and cash flows.operations.
NERC Compliance—NERC, at the direction of FERC, has implemented mandatory NERC Operations and CIPPlanning and Critical Infrastructure Protection standards to ensure the reliability of the U.S.North American Bulk Electric System, which includes electric transmission and generation systems, and to prevent major system black-outs.blackouts. NERC CIPCritical 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 CIPCritical 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 Authorityauthority 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 position limits on 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.
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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 Division ofNew Jersey Rate Counsel. WePSEG cannot predict the outcome of this matter. The nuclear plants are expected to receive
In October 2020, PSEG Power filed with the BPU its ZEC revenueapplications for approximately three years, through May 2022,Salem 1, Salem 2 and will be obligated to maintain operations during thatHope Creek for the three-year eligibility period subject to exceptions specifiedstarting in the ZEC legislation. The ZEC legislation requires nuclear plants to reapply for any subsequent three-year periods.June 2022.
In the event that (i) the ZEC program is overturned or is otherwise materially adversely modified through legal process, (ii) the terms and conditions of the subsequent period under the ZEC program, including the amount of ZEC payments that may be awarded materiallyor 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,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 retire cease to operateall of these plants subsequent to the initial ZEC period at or prior to a scheduled refueling outage.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 would stillwill take all necessary steps to retirecease to operate all of these plants. Theplants and will incur associated costs and accounting charges associated with any such retirement, whichcharges. These may include, among other things, accelerated depreciation and amortization orone-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. Inparticular,For a discussion of recent changes in December 2019, FERC issued an order establishing new rules for PJM’s capacity market whereby FERC extended the PJM MOPR to include both newenergy regulatory policies that may affect our business and existing resources that receive or are entitled to receive, certain out-of-market payments, with certain exemptions. States that have clean energy programs designed to achieve public policy goals can still choose to utilize the existing FRR approach, which provides a means other than PJM’s capacity auction for a generation resource to satisfy its capacity obligation.
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
32
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 resourcesresource 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. In particular:
33
including the impact of federal and would require further economic reviewstate laws and regulations relating to determine whether to continue operations or decommission any such station.
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.
ITEM 1B. UNRESOLVED STAFF COMMENTS
PSEG, PSE&G and PSEG Power
None.
ITEM 2. PROPERTIES
| Name | Location | Total Capacity (MW) | % Owned | Owned Capacity (MW) | Principal Fuels Used | |||||||||
| Steam: | ||||||||||||||
| Bridgeport Harbor (A) | CT | 383 | 100% | 383 | Coal | |||||||||
| New Haven Harbor | CT | 448 | 100% | 448 | Oil/Gas | |||||||||
| Total Steam | 831 | 831 | ||||||||||||
| Nuclear: | ||||||||||||||
| Hope Creek | NJ | 1,173 | 100% | 1,173 | 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 | 6,007 | 3,759 | ||||||||||||
| Combined Cycle: | ||||||||||||||
| Keys | MD | 761 | 100% | 761 | Gas | |||||||||
| Bergen | NJ | 1,229 | 100% | 1,229 | Gas/Oil | |||||||||
| Linden | NJ | 1,300 | 100% | 1,300 | Gas/Oil | |||||||||
| Sewaren 7 | NJ | 538 | 100% | 538 | Gas/Oil | |||||||||
| Bridgeport Harbor 5 (C) | CT | 484 | 100% | 484 | Gas | |||||||||
| Bethlehem | NY | 815 | 100% | 815 | Gas | |||||||||
| Kalaeloa | HI | 208 | 50% | 104 | Oil | |||||||||
| Total Combined Cycle | 5,335 | 5,231 | ||||||||||||
| 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 | CT | 17 | 100% | 17 | Oil | |||||||||
| Total Combustion Turbine | 1,188 | 1,188 | ||||||||||||
| Pumped Storage: | ||||||||||||||
| Yards Creek (D) | NJ | 420 | 50% | 210 | ||||||||||
| Total PSEG Power Plants | 13,781 | 11,219 | ||||||||||||
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, 2019,2020, PSE&G’s electric T&D system included approximately 25,000 circuit miles, and 858,000860,000 poles, of which 64% are jointly-owned. In addition, PSE&G owns and operates 5254 switching stations with an aggregate installed capacity of 37,35338,353 megavolt-amperes (MVA) and 244245 substations with an aggregate installed capacity of 8,4288,647 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, 2019,2020, 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, 2019,2020, PSE&G had 150owned 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.
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.
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
35
PART II
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 21, 2020,19, 2021, there were 55,98754,220 registered holders.
The following graph shows a comparison of the five-year cumulative return assuming $100 invested on December 31, 20142015 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.
| 2014 | 2015 | 2016 | 2017 | 2018 | 2019 | |||||||||||||||||||||
| PSEG | $ | 100.00 | $ | 97.22 | $ | 114.50 | $ | 139.43 | $ | 145.94 | $ | 170.87 | ||||||||||||||
| S&P 500 | $ | 100.00 | $ | 101.37 | $ | 113.49 | $ | 138.26 | $ | 132.19 | $ | 173.80 | ||||||||||||||
| DJ Utilities | $ | 100.00 | $ | 96.93 | $ | 114.55 | $ | 129.85 | $ | 132.43 | $ | 168.57 | ||||||||||||||
| S&P Electrics | $ | 100.00 | $ | 95.16 | $ | 110.65 | $ | 124.05 | $ | 129.15 | $ | 163.24 | ||||||||||||||
| 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 18, 2020,16, 2021, our Board of Directors approved a $0.49$0.51 per share common stock dividend for the first quarter of 2020.2021. This reflects an indicative annual dividend rate of $1.96$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 November 2019,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 vestbe issued in 2020.2021 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 2019.2020.
The following table indicates the securities authorized for issuance under equity compensation plans as of December 31, 2019:2020:
36
| Plan Category | Number of Securities to be Issued upon Exercise of Outstanding Options, Warrants and Rights | Weighted-Average Exercise Price of Outstanding Options, Warrants and Rights | Number of Securities Remaining Available for Future Issuance under Equity Compensation Plans | |||||||||||||||||||||||
| — | $ | — | ||||||||||||||||||||||||
| — | — | |||||||||||||||||||||||||
| Total | — | $ | — | |||||||||||||||||||||||
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.
ITEM 6. SELECTED FINANCIAL DATA
| PSEG | ||||||||||||||||||||||
| Years Ended December 31, | 2019 | 2018 | 2017 | 2016 | 2015 | |||||||||||||||||
| Millions, except Earnings per Share | ||||||||||||||||||||||
| Operating Revenues (A) | $ | 10,076 | $ | 9,696 | $ | 9,094 | $ | 8,966 | $ | 10,415 | ||||||||||||
| Income from Continuing Operations (B)(C)(D)(E) | $ | 1,693 | $ | 1,438 | $ | 1,574 | $ | 887 | $ | 1,679 | ||||||||||||
| Net Income (B)(C)(D)(E) | $ | 1,693 | $ | 1,438 | $ | 1,574 | $ | 887 | $ | 1,679 | ||||||||||||
| Earnings per Share: | ||||||||||||||||||||||
| Income from Continuing Operations | ||||||||||||||||||||||
| Basic | $ | 3.35 | $ | 2.85 | $ | 3.12 | $ | 1.76 | $ | 3.32 | ||||||||||||
| Diluted | $ | 3.33 | $ | 2.83 | $ | 3.10 | $ | 1.75 | $ | 3.30 | ||||||||||||
| Net Income | ||||||||||||||||||||||
| Basic | $ | 3.35 | $ | 2.85 | $ | 3.12 | $ | 1.76 | $ | 3.32 | ||||||||||||
| Diluted | $ | 3.33 | $ | 2.83 | $ | 3.10 | $ | 1.75 | $ | 3.30 | ||||||||||||
| Dividends Declared per Share | $ | 1.88 | $ | 1.80 | $ | 1.72 | $ | 1.64 | $ | 1.56 | ||||||||||||
| As of December 31, | ||||||||||||||||||||||
| Total Assets | $ | 47,730 | $ | 45,326 | $ | 42,716 | $ | 40,070 | $ | 37,535 | ||||||||||||
| Long-Term Obligations | $ | 13,743 | $ | 13,168 | $ | 12,071 | $ | 10,897 | $ | 8,837 | ||||||||||||
Omitted pursuant to conditions set forth in General Instruction I of Form 10-K.SEC Release 33-10890.
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. 37 |
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;Agreement (OSA); PSEG Energy Holdings L.L.C. (Energy Holdings), which primarily hasearns it revenues from its portfolio of lease investments and holds our investment in leveraged leases;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 20192020 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 20172018 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, 20182019 and December 31, 2017,2018, 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, 2018 (20182019 (2019 Annual Report) as filed with the Securities and Exchange Commission on February 27, 2019.26, 2020.
EXECUTIVE OVERVIEW OF 20192020 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 is designed to achievefocuses on achieving growth while controlling costs and managing the risks associated with regulatory changes, fluctuating commodity prices and changes in customer demand. OverIn 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, 2024,2025, PSE&G expects to invest between $11.5$13 billion to $15 billion, resulting in an expected compound annual rate base growth of 6.5% to 8%. These rangesThe 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 Clean Energy Future (CEF)Strong (ES) program, which otherwise concludes in 2023, as well as the remaining portion of our CEF proposal (portion of Electric Vehicle (EV) and incremental reliability and resiliency investments anticipated in the 2024 timeframe that we intend to seek approval for under the third phase of existing infrastructure programs.Energy Storage (ES) programs). See below for a description of the CEF program.
In 2019, we commenced our BPU-approved Gas System Modernization ProgramGSMP II, (GSMP II), an expanded, five-year program to invest $1.9 billion beginning in 2019 to replace approximately 875 miles of cast iron and unprotected steel mains in addition to other improvements to the gas system. Approximately $1.6 billion will be recovered through periodic rate roll-ins, with the remaining $300 million to be recovered through a future base rate proceeding. As part of the settlement approved by the BPU,
PSE&G agreed to file for a
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base rate proceeding no later than December 2023, to maintain a base level of gas distribution capital expenditures of $155 million per year and to achieve certain leakleakage 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 Energy StrongES 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, which is required to be filed no later thancase. As of December 2023.31, 2020, we had invested $156 million.
In October 2018, we filed our proposed CEF program with the BPU, a six-year estimated $3.5 billion investment covering four programs; (i) an Energy Efficiency (EE) program totaling $2.5 billion of investment designed to achieve energy efficiency targets required underJanuary 2020, New Jersey’s Clean Energy law; (ii) an Electric Vehicle (EV) infrastructure program; (iii) an Energy Storage (ES) program and (iv) an Energy Cloud (EC) program which will include installing approximately two million electric smart meters and associated infrastructure. The BPU is reviewing the CEF-EE program concurrently with its efforts to complete a stakeholder process to define key terms and policy parameters regarding returns, amortization and lost revenue recovery related to implementing energy efficiency programs statewide. Additionally, the StateJersey released its Energy Master Plan in January 2020,(EMP) which, is supportiveamong other things, recognizes the importance of energy efficiency but gives the BPU discretion in implementation between state-and utility-operated programs. State’s EE targets and supported EVs, ES, and advanced metering infrastructure (AMI).
In FebruarySeptember 2020, PSE&G reached an agreementa settlement with all parties in the CEF-EE matterproceeding, which was approved by 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) extend several existing EE programsa baseline of the test year in our last base rate case from July 2017 to June 2018. The deferral period for six months,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 an additional $111PSE&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, investmentinvested over the coursenext 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 programs, and (b) extend the timeline for reviewcomponents of the CEF-EE filing through September 2020. In addition,program. The approved investment under the BPU has circulatedprogram is for $166 million, primarily relating to preparatory work to deliver infrastructure to the parties procedural schedulescharging point for three programs: residential smart charging; Level-2 mixed use charging; and direct current fast charging.
All of the proposed $1 billion investmentcapital 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 andproposal, the vehicle innovation subprogram, as well as the overall CEF-ES programs.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 2020-20222021-2023 is $2.8$2.5 billion.
As noted above, PSE&G has been deemed by New Jersey to provide essential services during the ongoing coronavirus pandemic. Our capital programs, including GSMP II, ES II and our transmission infrastructure investments, have not been materially impacted to date. However, a prolonged outbreak and the associated economic impacts, which could extend beyond the duration of the pandemic, could impact our ability to obtain necessary permits and approvals and could lead to shortages of necessary materials, supplies and labor. In addition, a determination by any state or federal regulatory authority that one or all of our projects is non-essential could require us to temporarily halt work. Any delay in our planned capital program could impact our operational performance and could materially impact our results of operations and financial condition through decreased cost recovery.
Further, the ongoing coronavirus pandemic has led many state and federal agencies to implement remote working protocols and divert resources to address the pandemic which, if prolonged, could impact regulatory agencies’ ability to review proposed programs and delay the timing of approvals for matters subject to regulatory approval, including the approval of various clause recovery mechanisms.
PSE&G has experienced a reduction in demand from its commercial and industrial (C&I) customers, partially offset by increases in residential demand, and adverse changes to residential and C&I payment patterns. PSE&G expects these changes to continue during the prolonged coronavirus pandemic. In October 2020, the state formally extended its moratorium on non-safety related service disconnections for non-payment for residential customers through March 15, 2021. During the moratorium, PSE&G has experienced a significant decrease in cash inflow and higher Accounts Receivable aging and an associated increase in bad debt expense, which we expect could extend beyond the duration of the coronavirus pandemic.PSE&G’s electric distribution bad debt expense is recoverable through its Societal Benefits Clause (SBC) mechanism. PSE&G
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has deferred its incremental gas distribution bad debt expense as a result of COVID-19 as a Regulatory Asset and will seek recovery of that cost, as well as other net incremental COVID-19 costs, in its next base rate case.
In July 2020, the BPU authorized regulated utilities in New Jersey, including PSE&G, to create a COVID-19-related Regulatory Asset by deferring on their books and records the prudently incurred incremental costs related to COVID-19 beginning on March 9, 2020 through September 30, 2021, or 60 days after the New Jersey governor determines that the Public Health Emergency is no longer in effect, or in the absence of such a determination, 60 days from the time the Public Health Emergency automatically terminates by law, whichever is later. Deferred costs are to be offset by any federal or state assistance that the utility may receive as a direct result of the COVID-19 pandemic. During 2020, PSE&G recorded a Regulatory Asset related to COVID-19 to defer incremental costs of $51 million, which PSE&G believes are recoverable under the BPU order.
While the impact on our results of operations, financial condition and cash flows for the year ended December 31, 2020 has not been material, a prolonged coronavirus pandemic and the associated economic impacts, which could extend beyond the duration of the pandemic, could materially impact cash from operations, Accounts Receivable and bad debt expense.
PSEG Power
In July 2020, we announced that we are exploring strategic alternatives for PSEG Power’s non-nuclear generating fleet with the intention of accelerating the transformation of our business into a primarily regulated electric and gas utility, with a contracted generation business. It is expected to reduce overall business risk and earnings volatility, improve PSEG’s credit profile and is consistent with PSEG’s climate strategy and sustainability efforts, which is to focus on clean energy investments, methane reduction, and zero-carbon generation. PSEG intends to retain ownership of PSEG Power’s existing nuclear fleet. Since the announcement, we have engaged in proprietary activities relating to the potential divestiture of, and begun the marketing processes for these assets and any potential transactions are expected to be completed sometime in 2021. There is no assurance that the strategic review will result in a sale or other disposition of all or any portion of these assets on terms that are favorable to us, or at all. Any transaction would be subject to market conditions and customary closing conditions, including the receipt of all required regulatory approvals.
At PSEG Power, we strivehave sought to improve performanceachieve operational excellence and reducemanage 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. PSEG Power continues to move its fleet toward improved efficiency and believes that its recently completed investment program enhances its competitive position with the addition of efficient, clean, reliable combined cycle gas turbine capacity. In 2019,During 2020, our natural gas fleetand nuclear units generated 2322.1 and 30.8 terawatt hours and our nuclear fleet achievedoperated at a capacity factor of 88.7%.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 and abilityhelp to capitalize on market opportunities help it to balancemanage some of the volatility of the merchant power business. More than 70% of PSEG Power’s expected gross margin in 20202021 relates to hedging of our energy margin, our expected revenues from the capacity market mechanisms, Zero Emission Certificate (ZEC) revenues that commenced in April 2019 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 completedexperienced 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 1,800 MW combined cycle gas turbine construction programgeneration facilities and contractors working at the facilities during planned outages. A prolonged unavailability of employees and contractors due to the ongoing coronavirus pandemic could materially and adversely impact our ability to operate our generation facilities, which would have a material impact on our business, results of operations and cash flows.
PSEG LI
Following the effects of Tropical Storm Isaias, the New York Attorney General initiated an inquiry into PSEG LI’s preparation and response to the storm. In addition, the Department of Public Service (DPS) within the New York State Public Service Commission launched an investigation of state electric service providers, including PSEG LI, and other state telephone, cable and internet providers into their preparation and restoration efforts following Tropical Storm Isaias.Although the inquiry by the New York Attorney General remains pending, the DPS issued an interim storm investigation report. With respect to PSEG LI, the DPS’ report found that PSEG LI violated its Emergency Response Plan and DPS Regulations, and recommended that LIPA
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consider taking various actions, including terminating or renegotiating the OSA. LIPA also initiated its own review of PSEG LI’s performance and issued a report with recommendations for improvements to PSEG LI’s structure and processes, including a timeline for implementing those recommendations. That report also recommended that LIPA either renegotiate or terminate the OSA.
PSEG LI agreed with LIPA that it would fund approximately $6.5 million in claims by customers for food and medication spoilage costs incurred as a result of being without electric service during the storm.
In December 2020, LIPA filed a complaint against PSEG LI in New York State court alleging multiple breaches of the OSA in connection with PSEG LI’s preparation for and response to Tropical Storm Isaias seeking specific performance and $70 million in damages. Pursuant to recommendations by the New York State Department of Public Service, LIPA has initiated a series of actions to allow its board to determine whether to seek to terminate the OSA or instead continue with PSEG LI as its Service Provider.
PSEG LI is fully cooperating with the additioninquiries 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 Keys Energy Center (Keys)OSA; however a decision in Marylandthis 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 Sewaren 7financial 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 New Jersey in 2018a future where customers universally use less energy, the energy they use is cleaner, and Bridgeport Harbor Station Unit 5 (BH5) in Connecticut in 2019. These additionsits delivery is more reliable and more resilient. In July 2019, we announced that we expect to our fleet both expand our geographic diversity and adjust our fuel mix and enhance the environmental profile and overall efficiency ofcut carbon emissions at PSEG Power’s generation fleet.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. In 2019, our
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 20192020 as we
•maintained sufficient liquidity,
•maintained solid investment grade credit ratings, and
•increased our annual dividend for 20192020 to $1.88$1.96 per share.
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We expect to be able to fund our planned capital requirements, as described in Liquidity and Capital Resources and the impacts of the Tax Cuts and Jobs Act of 2017 (Tax Act) without the issuance of new equity. For additional information onOur planned capital requirements, which are driven by growth in our regulated utility, and the impactspotential sale of the Tax Act, see Item 8. Note 7. Regulatory Assetsour non-nuclear generation fleet are expected to help support our business and Liabilities and Note 22. Income Taxes.financial profile.
Financial Results
The financial results for PSEG, PSE&G and PSEG Power for the years ended December 31, 20192020 and 20182019 are presented as follows:
| Years Ended December 31, | ||||||||||
| 2019 | 2018 | |||||||||
| Millions, except per share data | ||||||||||
| PSE&G | $ | 1,250 | $ | 1,067 | ||||||
| PSEG Power | 468 | 365 | ||||||||
| Other | (25 | ) | 6 | |||||||
| PSEG Net Income | $ | 1,693 | $ | 1,438 | ||||||
| PSEG Net Income Per Share (Diluted) | $ | 3.33 | $ | 2.83 | ||||||
| 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 20192020 over 20182019 increase in Net Income was due primarily to higher earnings from distribution rate reliefa gain on the sale of PSEG Power’s ownership interest in a generating facility in 2020 and transmission and distributiona loss on its ownership interests in two fossil plants in 2019, T&D investments at PSE&G MTM and Nuclear Decommissioning Trust (NDT) Fund gains in 2019 as compared to losses in the prior year and ZEC revenues in 2019 at PSEG Power, and pension credits resulting from retiree medical plan benefit changes in 2019.and OPEB credits. These increases were partially offset at PSEG Power by a lossmark-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 the salelower volumes of electricity sold in 2019 ofPJM and lower capacity revenues which were somewhat tempered by higher ZEC revenues and lower fuel costs at PSEG Power’s ownership interests in two fossil plants.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, reflecting our long-term approach to managing our company.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 deploying capitaldetermining how and seekwhen to investefficiently deploy capital. We principally explore opportunities for investment in areas that complement our existing business and provide reasonable risk-adjusted returns. These areas include upgradingreturns and continuously assess and optimize our energy infrastructure and improving our environmental footprint to align with public policy objectives.business mix as appropriate. In 2019,2020, 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
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 the company,us, see Item 1. Business—Regulatory Issues.
Transmission PlanningRate Proceedings and Return on Equity (ROE)
In March 2019, FERC issued a Notice of Inquiry (NOI) seeking comment on improvements to FERC’s electric transmission incentives policy to ensure that it appropriately encourages the development of the infrastructure needed to ensure grid reliability and reduce congestion to lower the cost of power for consumers. The NOI is intended to examine whether existing incentives, such as the 50 basis point adder for membership in the Regional Transmission Organization, should continue to be granted and whether new incentives should be established.
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appropriate. FERC’s order indicated that it would not be bound by this revised methodology when considering the just and reasonableness of a utility’s ROE be lowered. Other 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 Ownerstransmission owners and utilities in other jurisdictions. In parallel to these proceedings, and in light of declining interest rates and other market conditions,addition, over the past few years, several companies have negotiated settlements that have resulted in reduced ROEs.
We continue to analyzeare engaged in settlement discussions with the potential impactBPU Staff and the New Jersey Division of these methodologiesRate Counsel about the level of PSE&G’s base transmission ROE and cannot predict the outcome of ongoing ROE proceedings.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) alternativeservice 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 carbon dioxide (COCO2) emissions will be required to procure credits for each ton they emit. In response to RGGI, PJM initiated a process in 2019 to investigate the development of a carbon pricing mechanism that may mitigate the environmental and financial distortions that could occur when emissions “leak” from non-participating states to the RGGI states. If the process leads to a market solution, it could have a material impact on the value of PSEG Power’s generating fleet.
Environmental Regulation
We are subject to liability under environmental laws for the costs of remediating environmental contamination of property now or formerly owned by us and of property contaminated by hazardous substances that we generated. In particular, the historic operations of PSEG companies and the operations of numerous other companies along the Passaic and Hackensack Rivers are alleged by Federal and State agencies to have discharged substantial contamination into the Passaic River/Newark Bay Complex in violation of various statutes. We are also currently involved in a number of proceedings relating to sites where other hazardous substances may have been discharged and may be subject to additional proceedings in the future, and the costs of any such remediation efforts could be material.
For further information regarding the matters described above, as well as other matters that may impact our financial condition and results of operations, see Item 8. Note 15. Commitments and Contingent Liabilities.
Nuclear
In April 2019, PSEG Power’s Salem 1, Salem 2 and Hope Creek nuclear plants were awarded ZECs by the BPU. Pursuant to a process established by the BPU, ZECs are purchased from selected nuclear plants and recovered through a non-bypassable distribution charge in the amount of $0.004 per kilowatt-hour used (which is equivalent to approximately $10 per megawatt
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hour generated in payments to selected nuclear plants (ZEC payment)). These nuclear plants are expected to receive ZEC revenue for approximately three years, through May 2022, and will be obligated to maintain operations during that period, subject to exceptions specified in the ZEC legislation. PSEG Power has and will continue to recognize revenue monthly as the nuclear plants generate electricity and satisfy their performance obligations. The ZEC legislation requires nuclear plants to reapply for any subsequent three year periods. 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’sState’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 Division ofNew 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,process; (ii) the terms and conditions of the subsequent period under the ZEC program, including the amount of ZEC payments that may be awarded materiallyor 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,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 retirecease to operate all of these plants subsequent to the initial ZEC period at or prior to a scheduled refueling outage.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 would stillwill take all necessary steps to retirecease to operate all of these plants. RetirementCeasing 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 results.
In September 2019, PSEG Power completedJuly 2020, the sale of its ownership interestsInternal Revenue Service (IRS) issued final and proposed regulations addressing the limitation on deductible business interest expense contained in the KeystoneTax Cuts 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. PSEG Power has also 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.
In March 2020, the same economic conditions experienced by other less efficient natural gasfederal Coronavirus Aid, Relief, and coal generation facilities, which could require additional write-downsEconomic 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 residual values of Energy Holdings’ leveraged lease receivables associated with these facilities.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 Legislation
Act. For non-regulated businesses, the Tax Act enacted rules that set a cap on the amount of business interest that can be deducted in a
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given year. Any amount that is disallowed can be carried forward indefinitely. For 2018 and 2019, a portion of PSEG’s and PSEG Power’s interest was disallowed but is expected to be realized in future periods. However, certain aspects of the law are unclear. Therefore, we recorded taxes in 2018 and 2019 based on our interpretation of the relevant statute. 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 but not limited to,among other things, the Internal Revenue ServiceIRS 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. For additional information, see Item 8. Note 22. Income Taxes.
In July 2018, the State of New Jersey made changes to its income tax laws, including imposing a temporary surtax of 2.5% effective January 1, 2018 and 2019 and 1.5% in 2020 and 2021, as well as requiring corporate taxpayers to file in a combined reporting group as defined under New Jersey law starting in 2019. Both provisions includeThis provision includes an exemption for public utilities. We believe 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. There are certain aspects of the law that are not clear. We anticipate the State of 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.
Future Outlook
Our future success will depend on our ability to continue to maintain strong operational and financial performance in an environment with low gas prices, 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,
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 investors,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.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 20202021 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 Act and CARES Acts and future changes in federal and state tax laws, and
•the impact of reductionschanges in demand, and lower natural gas and electricity prices, and increasing environmental compliance costs.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.value and address the interests of our multiple stakeholders. In assessing our options, we consider a wide variety of factors, including the performance and prospects of our businesses; the views of employees, investors, regulators, customers and rating agencies; our existing indebtedness and restrictions it imposes; and tax considerations, among other things. Strategic options available to us include:
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•investments in T&D facilities to enhance reliability, resiliency and modernize the system to meet the growing needs and increasingly higher expectations of customers, and clean energy investments and/or generation projects, including offshore wind opportunities,such as CEF-EE, CEF-EV and CEF-ES,
•the disposition or reorganizationrestructuring of our merchant generation business or portions thereof or other existing businesses or the acquisition or development of new businesses,
•continued operations of our geographic footprint,nuclear generation facilities, to the extent there is sufficient certainty that their operation will render an acceptable risk-adjusted return, and
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 | ||||||||||||||||||||
| Years Ended December 31, | ||||||||||||||
| 2019 | 2018 | 2017 | ||||||||||||
| Earnings (Losses) | Millions | |||||||||||||
| PSE&G | $ | 1,250 | $ | 1,067 | $ | 973 | ||||||||
| PSEG Power (A)(B) | 468 | 365 | 479 | |||||||||||
| Other (B)(C) | (25 | ) | 6 | 122 | ||||||||||
| PSEG Net Income | $ | 1,693 | $ | 1,438 | $ | 1,574 | ||||||||
| PSEG Net Income Per Share (Diluted) | $ | 3.33 | $ | 2.83 | $ | 3.10 | ||||||||
(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 NDTNuclear Decommissioning Trust (NDT) Fund activity and the impacts of non-trading commodity mark-to-market (MTM)MTM activity, which consist of the financial impact from positions with future delivery dates.
The variances in our Net Income attributable to changes related to the NDT Fund and MTM are shown in the following table:
| Years Ended December 31, | 2020 | 2019 | 2018 | |||||||||||||||||||||||
| Millions, after tax | ||||||||||||||||||||||||||
| NDT Fund and Related Activity (A) (B) | $ | 137 | $ | 152 | $ | (90) | ||||||||||||||||||||
| Non-Trading MTM Gains (Losses) (C) | $ | (58) | $ | 205 | $ | (84) | ||||||||||||||||||||
(A)NDT Fund Income (Expense) includes gains and losses on NDT securities which are recorded in Net Gains (Losses) on Trust Investments. See Item 8. Note 11. Trust Investments for additional information. NDT Fund Income (Expense) also includes interest and dividend income and other costs related to the NDT Fund recorded in Other Income (Deductions), interest accretion expense on PSEG Power’s nuclear Asset Retirement Obligation (ARO) recorded in Operation & Maintenance (O&M) Expense and the depreciation related to the ARO asset recorded in Depreciation and Amortization (D&A) Expense.
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| Years Ended December 31, | 2019 | 2018 | 2017 | |||||||||||
| Millions, after tax | ||||||||||||||
| NDT Fund and Related Activity (A) (B) | $ | 152 | $ | (90 | ) | $ | 62 | |||||||
| Non-Trading MTM Gains (Losses) (C) | $ | 205 | $ | (84 | ) | $ | (99 | ) | ||||||
(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 2019 $2552020 year-over-year increase of $212 million year-over-year increasein 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 and the favorable impact of new rates effective November 1, 2018 as a result of the BPU’s approval of our distribution base rate proceeding at PSE&G, and
•higher pension and OPEB credits,
•partially offset by MTM losses in 2020 as compared to significant gains in 2019 as compared to MTM losses in 2018 at PSEG Power, and
due to lower average realized prices on lower volumes of electricity sold in PJM and under the favorable impact of retiree medical plan benefit changes implemented in 2019, and
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) | |||||||||||||||||||||||||||||||||||||||||||
Increase / (Decrease) | Increase / (Decrease) | |||||||||||||||||||||||||||
| Years Ended December 31, | ||||||||||||||||||||||||||||
| 2019 | 2018 | 2017 | 2019 vs. 2018 | 2018 vs. 2017 | ||||||||||||||||||||||||
| Millions | Millions | % | Millions | % | ||||||||||||||||||||||||
| Operating Revenues | $ | 10,076 | $ | 9,696 | $ | 9,094 | $ | 380 | 4 | $ | 602 | 7 | ||||||||||||||||
| Energy Costs | 3,372 | 3,225 | 2,778 | 147 | 5 | 447 | 16 | |||||||||||||||||||||
| Operation and Maintenance | 3,111 | 3,069 | 2,901 | 42 | 1 | 168 | 6 | |||||||||||||||||||||
| Depreciation and Amortization | 1,248 | 1,158 | 1,986 | 90 | 8 | (828 | ) | (42 | ) | |||||||||||||||||||
| (Gain) Loss on Asset Dispositions | 402 | (54 | ) | — | 456 | N/A | (54 | ) | N/A | |||||||||||||||||||
| Income from Equity Method Investments | 14 | 15 | 14 | (1 | ) | (7 | ) | 1 | 7 | |||||||||||||||||||
| Net Gains (Losses) on Trust Investments | 260 | (143 | ) | 134 | 403 | N/A | (277 | ) | N/A | |||||||||||||||||||
| Other Income (Deductions) | 125 | 85 | 82 | 40 | 47 | 3 | 4 | |||||||||||||||||||||
| Non-Operating Pension and OPEB Credits (Costs) | 177 | 76 | — | 101 | N/A | 76 | N/A | |||||||||||||||||||||
| Interest Expense | 569 | 476 | 391 | 93 | 20 | 85 | 22 | |||||||||||||||||||||
| Income Tax (Benefit) Expense | 257 | 417 | (306 | ) | (160 | ) | (38 | ) | 723 | N/A | ||||||||||||||||||
The 2020, 2019 2018 and 20172018 amounts in the preceding table for Operating Revenues and O&M costs each include $520 million, $490 million $458 million and $438$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 Income Tax Benefit in 2017 includes the non-cash benefit resulting from the remeasurement of deferred tax liabilities required due to the enactment of the Tax Act in December 2017. 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 | |||||||||||||||||||||||||||||||||||||||||||
| Years Ended December 31, | Increase / (Decrease) | Increase / (Decrease) | ||||||||||||||||||||||||||
| 2019 | 2018 | 2017 | 2019 vs. 2018 | 2018 vs. 2017 | ||||||||||||||||||||||||
| Millions | Millions | % | Millions | % | ||||||||||||||||||||||||
| Operating Revenues | $ | 6,625 | $ | 6,471 | $ | 6,324 | $ | 154 | 2 | $ | 147 | 2 | ||||||||||||||||
| Energy Costs | 2,738 | 2,520 | 2,421 | 218 | 9 | 99 | 4 | |||||||||||||||||||||
| Operation and Maintenance | 1,581 | 1,575 | 1,458 | 6 | — | 117 | 8 | |||||||||||||||||||||
| Depreciation and Amortization | 837 | 770 | 685 | 67 | 9 | 85 | 12 | |||||||||||||||||||||
| Net Gains (Losses) on Trust Investments | 2 | (1 | ) | 2 | 3 | N/A | (3 | ) | N/A | |||||||||||||||||||
| Other Income (Deductions) | 83 | 80 | 85 | 3 | 4 | (5 | ) | (6 | ) | |||||||||||||||||||
| Non-Operating Pension and OPEB Credits (Costs) | 150 | 59 | (8 | ) | 91 | N/A | 67 | N/A | ||||||||||||||||||||
| Interest Expense | 361 | 333 | 303 | 28 | 8 | 30 | 10 | |||||||||||||||||||||
| Income Tax Expense | 93 | 344 | 563 | (251 | ) | (73 | ) | (219 | ) | (39 | ) | |||||||||||||||||
Year Ended December 31, 20192020 as compared to 20182019
Operating Revenues increased $154decreased $17 million due to changes in delivery, clause, commodity and other operating revenues.
Delivery Revenues decreased$67 million.increased $219 million.
•Transmission revenues increased $97$119 million due to higher revenue requirements calculated through our transmission formula rate, primarily to recover required investments.
•Gas distribution revenues increased $107$4 million due to $98 million from an increase in the distribution tariff rates effective November 1, 2018, $25of $30 million from collection of the Gas System Modernization Program (GSMP) and GSMP II in base rates and an increase in Weather Normalization Charge (WNC)WNC revenues of $1$19 million. These increases were partially offset by a $12$44 million decrease from lower sales volumes and $5$1 million in lower collections of Green Program Recovery Charges (GPRC).
•Electric distribution revenues increased $67$3 million due primarily to $75a $12 million from an increase in the distribution tariff rates effective November 1, 2018 and $16 million in higher collections of GPRC. These increases weresales volumes, partially offset by a $24$9 million decrease in sales volumes.lower collections of GPRC.
•Transmission, electric distribution and gas distribution revenue requirements were $338$93 million lowerhigher as a result of rate reductions due toa decrease in the flowback of excess deferred income tax liabilities and tax repair relatedrepair-related accumulated deferred income taxes. This decrease is offset in Income Tax Expense.
Clause Revenues decreased $2increased $30 million due to $11$24 million in Tax Adjustment Credits (TAC) and GPRC deferrals.deferrals and higher SBC charges of $13 million. These decreasesincreases were partially offset by a $6 million reduction in Margin Adjustment Clause (MAC) revenues $2and $1 million in higherlower Solar Pilot Recovery Charge (SPRC) collections and higher Societal Benefit Charges (SBC) of $1 million.collections. The changes in TAC and GPRC Deferrals, SBC, MAC SPRC and SBCSPRC 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 SPRC or SBCSPRC collections.
Commodity Revenues increased $98decreased $344 million due to higherlower Gas revenues partially offset byand 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 increased $102decreased $195 million due primarily to higher BGSS prices of $83 million and higherlower BGSS sales volumes of $19$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 $125$78 million due primarily to increases of $42 million in ZEC revenues billed after theand $33 million in SREC revenues. The changes in ZEC program was approved by the BPU in April 2019. See Item 8. Note 15. Commitmentsrevenues and Contingent Liabilities. The ZECSREC revenues are entirely offset by changes to Energy Costs.
Operating Expenses
Energy Costs increased $218decreased $269 million. This is entirely offset by changes in Commodity Revenues and Other Operating Revenues.
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Operation and Maintenance increased $6$33 million due primarily to a $42increases of $14 million net increase for various clause mechanismsin gas distribution maintenance costs, $13 million in vegetation management, $9 million in transmission maintenance expenditures, $7 million in storm-related costs and GPRC expenditures and a $4 million increase in injuriesdistribution corrective and damages.preventative maintenance expenditures. These increases were partially offset by a $19$4 million decrease in electric distribution maintenance expenditures, a $14 million decrease in transmission maintenance expendituresinjuries and damages and a $6$10 million decreasereduction in storm-related costs.other operating expenses.
Depreciation and Amortization increased$67 $50 million due primarily to an increase in depreciation of $52$45 million due to additional plant placed into service an $8 million increase due to new depreciation rates resulting from the distribution base rate settlement applied to assets held as of November 1, 2018 and a net $7$4 million increase from other factors.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 $91$55 million due primarily to a $103$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 mainly related to the December 2018 OPEB plan amendment and a $6 million decrease in interest cost, partially offset by a $17 million reduction in the expected return on plan assets.credit.
Interest Expense increased $28$27 million due primarily to increases of $18$23 million due to net long-term debt issuances in 2019 and $12 million due to net long-term debt issuances in 2018.2020 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 decreased $251increased $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 repair-related accumulated deferredbenefit from changes in uncertain tax positions as a result of the settlement of the 2011-2016 federal income taxes to ratepayers.tax audits.
Year Ended December 31, 20182019 as compared to 20172018
See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations in our 20182019 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 | |||||||||||||||||||||||||||||||||||||||||||
| Years Ended December 31, | Increase / (Decrease) | Increase / (Decrease) | ||||||||||||||||||||||||||
| 2019 | 2018 | 2017 | 2019 vs. 2018 | 2018 vs. 2017 | ||||||||||||||||||||||||
| Millions | Millions | % | Millions | % | ||||||||||||||||||||||||
| Operating Revenues | $ | 4,385 | $ | 4,146 | $ | 3,860 | $ | 239 | 6 | $ | 286 | 7 | ||||||||||||||||
| Energy Costs | 2,118 | 2,197 | 1,913 | (79 | ) | (4 | ) | 284 | 15 | |||||||||||||||||||
| Operation and Maintenance | 1,040 | 1,053 | 1,046 | (13 | ) | (1 | ) | 7 | 1 | |||||||||||||||||||
| Depreciation and Amortization | 377 | 354 | 1,268 | 23 | 6 | (914 | ) | (72 | ) | |||||||||||||||||||
| (Gain) Loss on Asset Dispositions | 402 | (54 | ) | — | 456 | N/A | (54 | ) | N/A | |||||||||||||||||||
| Income from Equity Method Investments | 14 | 15 | 14 | (1 | ) | (7 | ) | 1 | 7 | |||||||||||||||||||
| Net Gains (Losses) on Trust Investments | 253 | (140 | ) | 125 | 393 | N/A | (265 | ) | N/A | |||||||||||||||||||
| Other Income (Deductions) | 54 | 21 | 20 | 33 | N/A | 1 | 5 | |||||||||||||||||||||
| Non-Operating Pension and OPEB Credits (Costs) | 21 | 15 | 8 | 6 | 40 | 7 | 88 | |||||||||||||||||||||
| Interest Expense | 119 | 76 | 50 | 43 | 57 | 26 | 52 | |||||||||||||||||||||
| Income Tax Expense (Benefit) | 203 | 66 | (729 | ) | 137 | N/A | 795 | N/A | ||||||||||||||||||||
Year Ended December 31, 20192020 as compared to 20182019
Operating Revenues increased$239decreased $751 million due to changes in generation, gas supply and other operating revenues.
Generation Revenues increased $312decreased $613 million due primarily to
•a net increasedecrease of $374$369 million due to MTM gainslosses in 20192020 as compared to MTM lossesgains in 2018.2019. Of this amount, there was a $340$196 million increase from changes in forward prices in 2019 as compared to 2018, coupled with a $34 million increasedecrease due to more gainslosses on positions reclassified to realized upon settlement and
a net decrease of $63$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 NYPJM region primarily due to the sale of our ownership
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interests in the Keystone and Conemaugh generation plants in 2019. This was partially offset by higher volumes of electricity sold in the PJMNE region, primarily due to the commencement of commercial operations of Bridgeport Harbor Unit 5 (BH5) in June 2019 and NE regions,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 $16$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 commencement of commercial operations of Keys and Sewaren 7nuclear plants in mid-2018 and BH5 in June 2019.2020.
Gas Supply Revenues decreased $75 $138 million due primarily to
•a decrease of $107$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, primarilyof which $80 million was due to higher volumes sold, partially offset by $62 million due to lower volumes sold and 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 $79$297 million due to
•a net decrease of $90$176 million related to sales to third parties due primarily toin fuel costs reflecting lower gas prices in the PJM and NY regions coupled with the utilization of lower volumes soldof coal in the PJM region primarily due to the sale of our ownership interests in the Keystone and Conemaugh generation plants, and lower averagevolumes of gas costs,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 $40$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, primarilyof which $80 million was due to an increasea decrease in the average cost of gas.
to a net decrease in send out volumes. Included in the average cost of $21gas were $18 million of interstate gas pipeline refunds due to lower MTM losses in 2019 as compared to 2018, anda settlement on pipeline rates from prior periods,
•partially offset by a net increase of $13$18 million in higher fuel costs reflecting utilizationrelated to sales to third parties, of which $73 million was due to higher volumes of gas at Keys, Sewaren 7 and BH5, coupled with higher prices of gas in the PJM region,sold, partially offset by utilization of lower volumes and lower prices of gas$55 million due to a decrease in the NY region, lower pricesaverage cost of gas in the NE region, utilization of lower volumes of oil in the PJM region, and lower usage of coal at lower prices in the PJM and NE regions.gas.
Operation and Maintenance decreased $13$76 million due primarily to a net decrease at our fossil plants largely due to lower outage costs, decreased support costs and the sale of PSEG Power’sour ownership interests in the Keystone and Conemaugh generation plants in September 2019. The decrease was partially offset by2019 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, (see Note 12. Goodwill and Other Intangibles), increasedpartially offset by higher planned outage costs related to the Keys and Sewaren 7 being placed into service in mid-2018 and increased property taxes.2020.
Depreciation and Amortization increased $23decreased $9 million due primarily to Keys, Sewaren 7 and BH5 being placed into service,an extension of the Peach Bottom License which was approved by the NRC in March 2020, partially offset by the sale of PSEG Power’s ownership interests in the Keystone and Conemaugh generation plants.an increased asset base at Nuclear.
(Gain) Loss on Asset Dispositions reflects a$402 millionloss in 2019 related to gain on the sale of PSEG Power’sour 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 and a gain of $54 million in 2018 related to the sale of the Hudson and Mercer plants.2019. See Item 8. Note 4. Early Plant Retirements/Asset Dispositions.
Net Gains (Losses) on Trust Investments increased $393decreased $12 million due primarily to a $405$76 million increase resulting fromdecrease in net unrealized gains in 2019 as compared to net unrealized losses in 2018 on equity investments in the NDT Fund, partially offset by a $16$66 million decreaseincrease in net realized gains on NDT Fund investments.
Other Income (Deductions) increased$33decreased $42 million primarily due to $26 millionpurchases of NOLs in less purchased net operating losses2020 under New Jersey’s Technology Tax Benefit Transfer Program and higherlower interest and dividend income on NDT Fund investments.
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Non-Operating Pension and OPEB Credits (Costs) increased $6 $12 million due to a $19 million increase in the amortization of prior service credit mainly related to the December 2018 OPEB plan amendment, a $5$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 unrecognizedactuarial loss, largelypartially offset by a $20$3 million increase in co-owner charges and a $2 million decrease in the expected return on plan assets.amortization of net prior service credit.
Interest Expense increased $43$2 million due primarily to $17 million of lower capitalized interest in 2020 as a result of Keys and Sewaren 7BH5 being placed into service in mid-2018 and BH5 being place into service2019, partially offset by a decrease of $15 million due to debt maturities in June 2019.April 2020.
Income Tax Expense increased $137decreased $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, including higher pre-tax income from the NDT qualified fund which is subject to an additional trust tax, and the favorable impact that resulted in 2018 from the remeasurement of the reserve for uncertain tax positions. income.
Year Ended December 31, 20182019 as compared to 20172018
See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations in our 20182019 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.$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 dividend payments.dividends.
For the year ended December 31, 2019,2020, our operating cash flow increaseddecreased by $466 million.$277 million. The net changes weredecrease was primarily due to the net changes from our subsidiaries, as discussed below.below, and higher tax payments in 2020 at Energy Holdings, offset by net tax refunds in 2020 as compared to net tax payments in 2019 at the parent company.
Given the current economic challenges, PSE&G has informed both our residential customers and state regulators that all non-safety related service disconnections for non-payment will be temporarily suspended. In addition, the current economic
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PSE&G
PSE&G’s operating cash flow increased $182decreased $82 million from $1,853$2,035 million to $2,035$1,953 million for the year ended December 31, 2019,2020, as compared to 2018,2019, due primarily to an increase of $178 million from recoveries of regulatory deferrals andtax payments in 2020 as compared to tax refunds in 2019, as comparedincreased regulatory deferrals and higher Accounts Receivable reflecting lower collections due to tax payments in 2018,the economic impacts of the pandemic and the moratorium on collections, partially offset by $123 millionhigher earnings and decreases in increasedelectric energy and vendor payments.payables.
PSEG Power
PSEG Power’s operating cash flow increased $395decreased $368 million from $1,084$1,479 million to $1,479$1,111 million for the year ended December 31, 2019,2020, as compared to 2018,2019, due to a decrease$359 million reduction resulting from a modest increase in counterparty cash collateral posting requirements of $596 million,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 an $83higher earnings and a $51 million decreaseincrease from net collections of counterparty receivables, and lower tax refunds in 2019 as compared to 2018.receivables.
Short-Term Liquidity
PSEG meets its short-term liquidity requirements, as well as those of PSEG Power, primarily with cash and through the issuance of commercial paper.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, 20192020 were as follows:
| Company/Facility | As of December 31, 2019 | |||||||||||||
Total Facility | Usage | Available Liquidity | ||||||||||||
| Millions | ||||||||||||||
| PSEG | $ | 1,500 | $ | 796 | $ | 704 | ||||||||
| PSE&G | 600 | 379 | 221 | |||||||||||
| PSEG Power | 2,100 | 161 | 1,939 | |||||||||||
| Total | $ | 4,200 | $ | 1,336 | $ | 2,864 | ||||||||
| 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, 2019,2020, our credit facility capacity was in excess of our projected maximum liquidity requirements over our 12 month planning horizon.horizon, including access to capital to meet redemptions. Our maximum liquidity requirements are based on stress scenarios that incorporate changes in commodity prices and thepotential 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 $974$840 million and $857$974 million as of December 31, 20192020 and 2018,2019, respectively.
For additional information, see Item 8. Note 16. Debt and Credit Facilities.
Long-Term Debt Financing
During the next twelve months,
•PSEG has a $700 million floating rate term loan maturing in November 2020,
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•PSE&G has $300 million of 1.90% Medium-Term Notes, Series K, maturing in March 2021 and $134 million of 9.25% Mortgage Bonds Series CC maturing in June 2021, and
•PSEG Power has $700 million of 3.00% Senior Notes maturing in June 2021 and $250 million of 4.15% Senior Notes maturing in September 2021.
For a discussion of our long-term debt transactions during 2019,2020, 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, 2019,2020, PSE&G’s Mortgage coverage ratio was 4.53.3 to 1 and the Mortgage would permit up to approximately $7.6$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
53
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, that 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 hadaccumulated funding credits totaling approximately $600 million through 2020, which represent historical contributions in excess of IRS minimum funding requirements, and these credits can be applied to offset any future cash contribution obligations.
In addition, the NRC requires a biennial filing of the NDT fund balances against the decommissioning liability estimate. Any funding shortfalls are required to be cured prior to the next NRC reporting period. The market volatility associated in 2020 with the ongoing coronavirus pandemic did not result in any supplemental required funding of the NDT Fund. To the extent of a prolonged economic downturn associated with the ongoing coronavirus pandemic, our funding requirements may increase in future periods to meet NRC minimum funding requirements.
Common Stock Dividends
| Years Ended December 31, | ||||||||||||||||||||||||||
| Dividend Payments on Common Stock | 2020 | 2019 | 2018 | |||||||||||||||||||||||
| Per Share | $ | 1.96 | $ | 1.88 | $ | 1.80 | ||||||||||||||||||||
| in Millions | $ | 991 | $ | 950 | $ | 910 | ||||||||||||||||||||
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| Years Ended December 31, | ||||||||||||||
| Dividend Payments on Common Stock | 2019 | 2018 | 2017 | |||||||||||
| Per Share | $ | 1.88 | $ | 1.80 | $ | 1.72 | ||||||||
| in Millions | $ | 950 | $ | 910 | $ | 870 | ||||||||
On February 18, 2020,16, 2021, our Board of Directors approved a $0.49$0.51 per share common stock dividend for the first quarter of 2020.2021. This reflects an indicative annual dividend rate of $1.96$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 (Moody’s) and Corporate Credit Ratings (S&P) 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 | |||||||||||||||||
| Stable | Stable |
| Senior Notes | Baa1 | BBB | |||||||||||||||
| Commercial Paper | P2 | A2 | |||||||||||||||
| PSE&G | |||||||||||||||||
| 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 IncomeLoss
For the year ended December 31, 2019,2020, we had an Other Comprehensive Loss of $31$15 million on a consolidated basis. The Other Comprehensive Loss was due primarily to a decrease of $58$46 million related to pension and other postretirement benefits, and $14 million of unrealized losses on derivative contracts accounted for as hedges, partially offset by $41$25 million of net unrealized gains related to Available-for-Sale Securities.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 table below.following table. These projections include Allowance for Funds Used During ConstructionAFUDC 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 Gas System Modernization, Energy Strong and Clean Energy are forPSE&G include currently approved programs. We intend to continue to invest in infrastructure modernization and will seek to extend these and related programs as appropriate. We will also continue to approach potential growth investments for PSEG Power opportunistically, seeking projects that will provide attractive risk-adjusted returns for our shareholders.
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| 2020 | 2021 | 2022 | ||||||||||||
| Millions | ||||||||||||||
| PSE&G: | ||||||||||||||
| Transmission | $ | 1,200 | $ | 950 | $ | 660 | ||||||||
| Distribution | 855 | 800 | 920 | |||||||||||
| Gas System Modernization | 455 | 435 | 405 | |||||||||||
| Energy Strong | 110 | 275 | 270 | |||||||||||
| Clean Energy | 55 | 55 | 50 | |||||||||||
| Total PSE&G | $ | 2,675 | $ | 2,515 | $ | 2,305 | ||||||||
| PSEG Power: | ||||||||||||||
| Baseline | $ | 125 | $ | 105 | $ | 145 | ||||||||
| Other | 35 | 10 | 10 | |||||||||||
| Total PSEG Power | $ | 160 | $ | 115 | $ | 155 | ||||||||
| Other | $ | 25 | $ | 25 | $ | 25 | ||||||||
| Total PSEG | $ | 2,860 | $ | 2,655 | $ | 2,485 | ||||||||
| 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, solar loan programs and customer energy efficiency programs.programs, and infrastructure supporting electric vehicles.
In October 2018, we filedSeptember 2020, the BPU issued an Order approving our proposed CEFCEF-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 estimated $3.5 billion investment program focused on achieving New Jersey’s energy efficiency targets, supporting electric vehicle infrastructure, deploying energy storage,period. See Executive Overview of 2020 and implementing an EC program which will include installing approximately two million electric smart meters and associated infrastructure. The size and duration of the CEF program, as well as certain other elements of the program, are subject to BPU approval.
In 2019,2020, PSE&G made $2,542$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 $108$106 million, which are included in operating cash flows.
PSEG Power
PSEG Power’s projected expenditures for the various items listed above are primarily comprised of the following:
In 2019,2020, PSEG Power made $482$195 million of capital expenditures, excluding $125$209 million for nuclear fuel, primarily related to various projects at Fossilnuclear and Nuclear.solar projects.
Offshore Wind
The above table does not reflect our expected long-term investments in offshore wind projects. Following the completion of our acquisition of a 25% equity interest in Orsted’s Ocean Wind project, which is subject to the approval of the BPU and other customary closing conditions, we currently expect to make investments in the project in 2021 relating to our initial capital investment and to fund construction and operations planning activities. Over the course of the project, which could provide first power in late 2024, our investments are expected to be substantial.
Disclosures about Contractual Obligations
The following table reflects our contractual cash obligations in the respective periods in which they are due. In addition, the table summarizes anticipated debt maturities for the years shown. For additional information, see Item 8. Note 16. Debt and Credit Facilities.
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The table below does not reflect any anticipated cash payments for pension obligations due to uncertain timing of payments or liabilities for uncertain tax positions since we are unable to reasonably estimate the timing of liability payments in individual years beyond 12 months due to uncertainties in the timing of the effective settlement of tax positions. See Item 8. Note 22. Income Taxes for additional information.
| Total Amount Committed | Less Than 1 Year | 2 - 3 Years | 4 - 5 Years | Over 5 Years | ||||||||||||||||||||||||||||||||||
| Millions | ||||||||||||||||||||||||||||||||||||||
| Contractual Cash Obligations | ||||||||||||||||||||||||||||||||||||||
| Long-Term Recourse Debt Maturities | ||||||||||||||||||||||||||||||||||||||
| PSEG | $ | 2,946 | $ | 300 | $ | 700 | $ | 1,300 | $ | 646 | ||||||||||||||||||||||||||||
| PSE&G | 10,999 | 434 | 825 | 1,100 | 8,640 | |||||||||||||||||||||||||||||||||
| PSEG Power | 2,348 | 950 | 994 | — | 404 | |||||||||||||||||||||||||||||||||
| Interest on Recourse Debt | ||||||||||||||||||||||||||||||||||||||
| PSEG | 315 | 68 | 105 | 54 | 88 | |||||||||||||||||||||||||||||||||
| PSE&G | 6,650 | 390 | 756 | 683 | 4,821 | |||||||||||||||||||||||||||||||||
| PSEG Power | 487 | 93 | 132 | 70 | 192 | |||||||||||||||||||||||||||||||||
| Operating Leases | ||||||||||||||||||||||||||||||||||||||
| PSE&G | 127 | 16 | 24 | 18 | 69 | |||||||||||||||||||||||||||||||||
| PSEG Power | 89 | 14 | 22 | 6 | 47 | |||||||||||||||||||||||||||||||||
| Services | 150 | 15 | 30 | 30 | 75 | |||||||||||||||||||||||||||||||||
| Energy-Related Purchase Commitments | ||||||||||||||||||||||||||||||||||||||
| PSEG Power | 2,252 | 688 | 804 | 477 | 283 | |||||||||||||||||||||||||||||||||
| Total Contractual Cash Obligations | $ | 26,363 | $ | 2,968 | $ | 4,392 | $ | 3,738 | $ | 15,265 | ||||||||||||||||||||||||||||
| Liability Payments for Uncertain Tax Positions | ||||||||||||||||||||||||||||||||||||||
| PSEG | $ | 12 | $ | 12 | $ | — | $ | — | $ | — | ||||||||||||||||||||||||||||
| PSE&G | 12 | 12 | — | — | — | |||||||||||||||||||||||||||||||||
| PSEG Power | — | — | — | — | — | |||||||||||||||||||||||||||||||||
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 | $ | 2,450 | $ | 700 | $ | 1,000 | $ | 750 | $ | — | ||||||||||||
| PSE&G | 9,908 | 259 | 434 | 1,575 | 7,640 | |||||||||||||||||
| PSEG Power | 2,850 | 406 | 994 | 950 | 500 | |||||||||||||||||
| Interest on Recourse Debt | ||||||||||||||||||||||
| PSEG | 185 | 67 | 86 | 32 | — | |||||||||||||||||
| PSE&G | 6,146 | 374 | 702 | 660 | 4,410 | |||||||||||||||||
| PSEG Power | 697 | 123 | 183 | 110 | 281 | |||||||||||||||||
| Operating Leases | ||||||||||||||||||||||
| PSE&G | 126 | 15 | 23 | 17 | 71 | |||||||||||||||||
| PSEG Power | 100 | 13 | 28 | 11 | 48 | |||||||||||||||||
| Services | 165 | 15 | 30 | 30 | 90 | |||||||||||||||||
| Other | 3 | 1 | 2 | — | — | |||||||||||||||||
| Energy-Related Purchase Commitments | ||||||||||||||||||||||
| PSEG Power | 2,468 | 761 | 854 | 456 | 397 | |||||||||||||||||
| Total Contractual Cash Obligations | $ | 25,098 | $ | 2,734 | $ | 4,336 | $ | 4,591 | $ | 13,437 | ||||||||||||
| Liability Payments for Uncertain Tax Positions | ||||||||||||||||||||||
| PSEG | $ | 190 | $ | 190 | $ | — | $ | — | $ | — | ||||||||||||
| PSE&G | 107 | 107 | — | — | — | |||||||||||||||||
| PSEG Power | 77 | 77 | — | — | — | |||||||||||||||||
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 principlesguidance generally accepted in the United States (GAAP) for leases. Leveraged lease investments generally involve three
Accounting for Pensions and OPEBOther Postretirement Benefits (OPEB)
PSEG sponsors qualified and nonqualified pension plans and OPEB plans covering PSEG’s and its participating affiliates’ current and former employees who meet certain eligibility criteria. In late June 2019, PSEG approved a plan amendment to its qualified pension plan, effective July 1, 2019. The amendment involved the spin-off of predominantly active participants from the existing qualified pension plan (Pension Plan) into a new qualified pension plan (Pension Plan II). See Item 8. Note 14. Pension, Other Postretirement Benefits (OPEB) and Savings Plans for additional information. The market-related value of plan assets held for the qualified pension and OPEB plans is equal to the fair value of these assets as of year-end. The plan assets are comprised of investments in both debt and equity securities which are valued using quoted market prices, broker or dealer quotations, or alternative pricing sources with reasonable levels of price transparency. Plan assets also include investments in
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unlisted real estate which is valued via third-party appraisals. We calculate pension and OPEB costs using various economic and demographic assumptions.
Assumptions and Approach Used: Economic assumptions include the discount rate and the long-term rate of return on trust assets. Demographic pension and OPEB assumptions include projections of future mortality rates, pay increases and retirement patterns, as well as projected health care costs for OPEB.
| Assumption | 2019 | 2018 | 2017 | ||||||||
| Pension | |||||||||||
| Discount Rate | 3.30 | % | 4.41 | % | 3.73 | % | |||||
| Expected Rate of Return on Plan Assets | 7.80 | % | 7.80 | % | 7.80 | % | |||||
| OPEB | |||||||||||
| Discount Rate | 3.20 | % | 4.31 | % | 3.76 | % | |||||
| Expected Rate of Return on Plan Assets | 7.79 | % | 7.80 | % | 7.80 | % | |||||
| 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 twentynineteen 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 3.30%2.61% discount rate for 20202021 pension costs/credits and a 3.20%2.46% discount rate for 20202021 OPEB costs/credits. Based upon these assumptions, we have estimated a net periodic pension credit in 20202021 of approximately $28$82 million, or $84$142 million, net of amounts capitalized, and a net periodic OPEB credit in 20202021 of approximately $77$96 million, or $81$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, 2019 | Increase to Costs in 2020 | Increase to Costs, net of Amounts Capitalized in 2020 | |||||||||||||
| Assumption | Millions | |||||||||||||||
| Pension | ||||||||||||||||
| Discount Rate | (1)% | $ | 923 | $ | 33 | $ | 22 | |||||||||
| Expected Rate of Return on Plan Assets | (1)% | N/A | $ | 57 | $ | 57 | ||||||||||
| OPEB | ||||||||||||||||
| Discount Rate | (1)% | $ | 145 | $ | 14 | $ | 13 | |||||||||
| Expected Rate of Return on Plan Assets | (1)% | N/A | $ | 5 | $ | 5 | ||||||||||
| % Change | Impact on Benefit Obligation as of December 31, 2020 | Increase to Costs in 2021 | Increase to Costs, net of Amounts Capitalized in 2021 | |||||||||||||||||||||||||||||
| Assumption | Millions | |||||||||||||||||||||||||||||||
| Pension | ||||||||||||||||||||||||||||||||
| Discount Rate | (1)% | $ | 987 | $ | 37 | $ | 26 | |||||||||||||||||||||||||
| Expected Rate of Return on Plan Assets | (1)% | N/A | $ | 62 | $ | 62 | ||||||||||||||||||||||||||
| OPEB | ||||||||||||||||||||||||||||||||
| Discount Rate | (1)% | $ | 143 | $ | 17 | $ | 16 | |||||||||||||||||||||||||
| Expected Rate of Return on Plan Assets | (1)% | N/A | $ | 5 | $ | 5 | ||||||||||||||||||||||||||
See Item 7A. Quantitative and Qualitative Disclosures About Market Risk for additional information.
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Derivative Instruments
The operations of PSEG, PSEG Power and PSE&G are exposed to market risks from changes in commodity prices, interest rates and equity prices that could affect their results of operations and financial condition. Exposure to these risks is managed through normal operating and financing activities and, when appropriate, through executing derivative transactions. Derivative instruments are used to create a relationship in which changes to the value of the assets, liabilities or anticipated transactions exposed to market risks are expected to be offset by changes in the value of these derivative instruments.
Current accounting guidance requires us to recognize all derivatives on the balance sheet at their fair value, except for derivatives that qualify for and are designated as normal purchases and normal sales contracts.
Assumptions and Approach Used: In general, the fair value of our derivative instruments is determined primarily by end of day clearing market prices from an exchange, such as the New York Mercantile Exchange, Intercontinental Exchange and Nodal Exchange, or auction prices. Fair values of other energy contracts may be based on broker quotes.
For a small number of contracts where limited observable inputs or pricing information are available, modeling techniques are employed in determination of their fair value using assumptions reflective of contractual terms, current market rates, forward price curves, discount rates and risk factors, as applicable.
For our wholesale energy business, many of the forward sale, forward purchase, option and other contracts are derivative instruments that hedge commodity price risk, but do not meet the requirements for, or are not designated as, either cash flow or fair value hedge accounting. The changes in value of such derivative contracts are marked to market through earnings as the related commodity prices fluctuate. As a result, our earnings may experience significant fluctuations depending on the volatility of commodity prices.
Effect if Different Assumptions Used: Any significant changes to the fair market values of our derivatives instruments could result in a material change in the value of the assets or liabilities recorded on our Consolidated Balance Sheets and could result in a material change to the unrealized gains or losses recorded in our Consolidated Statements of Operations.
For additional information regarding Derivative Financial Instruments, see Item 8. Note 1. Organization, Basis of Presentation and Summary of Significant Accounting Policies, Note 18. Financial Risk Management Activities and Note 19. Fair Value Measurements.
Long-Lived Assets
Management evaluates long-lived assets for impairment and reassesses the reasonableness of their related estimated useful lives whenever events or changes in circumstances warrant assessment. Such events or changes in circumstances may be as a result of significant adverse changes in regulation, business climate, counterparty credit worthiness, market conditions, or a determination that it is more-likely-than-not that an asset or asset group will be sold or retired before its estimated useful life, an asset group’s carrying amount may not be recoverable or an asset’s probability of operating through its estimated remaining useful life changes.
Assumptions and Approach Used: In the event certain triggers exist indicating an asset/asset group may not be recoverable, an undiscounted cash flow test is performed to determine if an impairment exists. When the carrying value of a long-lived asset/asset group exceeds the undiscounted estimate of future cash flows associated with the asset/asset group, an impairment may exist to the extent that the fair value of the asset/asset group is less than its carrying amount.
For PSEG Power, cash flows for long-lived assets and asset groups are determined at the lowest level for which identifiable cash flows are largely independent of the cash flows of other assets and liabilities. The cash flows from the generation units are generally evaluated at a regional portfolio level (PJM, NYISO, ISO-NE), regardless of generation fuel type, along with cash flows generated from the customer supply and risk management activities, inclusive of cash flows from contracts, including those that are accounted for as derivatives and meet the normal purchases and normal sales scope exception. In certain cases, generation assets are evaluated on an individual basis where those assets are individually contracted on a long-term basis with a third party and operations are independent of other generation assets (typically PSEG Power’s solar plantsunits 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, and the cost of borrowing.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 solarassets, as of September 30, 2020 and December 31, 2020. The assessments included probability weightings assigned to undiscounted cash flow scenarios of retaining the assets through
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the end of their estimated useful lives and a successful disposition of the non-nuclear assets in 2021. Estimates of cash flows associated with a sale scenario were based on management’s expectations of the fair value of such assets. The probability weighted aggregation of undiscounted cash flows for each of the asset groupings expected to result from the use and potential disposition of the asset groups exceeded their carrying value at the above mentioned September 30, 2020 and December 31, 2020 assessment dates. As such, it demonstrated that no impairment exists for any of the asset groupings and they continue to remain classified as held for use as of December 31, 2020. Management expects that a change in the probability of a successful disposition based upon further progression in the marketing process, but prior to meeting all necessary held-for-sale classification criteria, would result in an impairment of the ISO-NE asset grouping, which would be material. Furthermore, a change to a held-for-sale classification from a held-for-use classification would result in an impairment of the PJM, NYISO and ISO-NE asset groupings, which would be material.
In addition, long-lived assets are depreciated under the straight-line method based on estimated useful lives. An asset’s operating useful life is generally based upon operational experience with similar asset types and other non-operational factors. In the ordinary course, management, together with an asset’s co-owners in the case of certain of our jointly-owned assets, makes a number of decisions that impact the operation of our generation assets beyond the current year. These decisions may have a direct impact on the estimated remaining useful lives of our assets and will be influenced by the financial outlook of the assets, including future market conditions such as forward energy and capacity prices, operating and capital investment costs and any state or federal legislation and regulations, among other items.
Effect if Different Assumptions Used: The above cash flow tests, and fair value estimates and estimated remaining useful lives may be impacted by a change in the assumptions noted above and could significantly impact the outcome, triggering additional impairment tests, write-offs or accelerated depreciation. For additional information on the potential impacts on our future financial statements that may be caused by a change in useful lives of certain of our generating assets. Seethe assumptions noted above, see Item 8. Note 4. Early Plant Retirements/Asset Dispositions and Note 6. Property, Plant and Equipment and Jointly-Owned Facilities.
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 $740$852 million of PSEG Power’s total AROs as of December 31, 2019.2020. PSEG Power determines its AROs for its nuclear units by assigning probability weighting to various discounted cash flow outcomes for each of its nuclear units that incorporate the assumptions above as well as:
•financial feasibility and impacts on potential early shutdown,
•license renewals,
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•SAFSTOR alternative, which assumes the nuclear facility can be safely stored and subsequently decommissioned in a period within 60 years after operations,
•DECON alternative, which assumes decommissioning activities begin after operations, and
•recovery from the federal government of costs incurred for spent nuclear fuel.
Effect if Different Assumptions Used: Changes in the assumptions could result in a material change in the ARO balance sheet obligation and the period over which we accrete to the ultimate liability. Had the following assumptions been applied, our estimates of the approximate impacts on the Nuclear ARO as of December 31, 20192020 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 $275$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 $379$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 retireretires Salem 1 and Hope Creek and Salem 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 $203$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.
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
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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, | 2019 | 2018 | ||||||||
| 95% Confidence Level, Loss could exceed VaR one day in 20 days | ||||||||||
| Period End | $ | 9 | $ | 21 | ||||||
| Average for the Period | $ | 12 | $ | 14 | ||||||
| High | $ | 35 | $ | 46 | ||||||
| Low | $ | 5 | $ | 6 | ||||||
| 99.5% Confidence Level, Loss could exceed VaR one day in 200 days | ||||||||||
| Period End | $ | 14 | $ | 32 | ||||||
| Average for the Period | $ | 19 | $ | 22 | ||||||
| High | $ | 54 | $ | 72 | ||||||
| Low | $ | 8 | $ | 9 | ||||||
| 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, 2019,2020, 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 $401$357 million decrease in the fair value of debt, including a $14$16 million decrease at PSEG, a $353$328 million decrease at PSE&G and a $34$13 million decrease at PSEG Power.
Debt and Equity Securities
We have $6.5$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,
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•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, 2019,2020, the portfolio included $1.2$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, 2019,2020, a hypothetical 10% change in the equity market would impact the value of the equity securities in the NDT Fund by approximately $115$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 5.876.22 years and a yield of 2.32%1.14%. The portfolio’s value will appreciate or depreciate by the duration with a 1% change in interest rates. As of December 31, 2019,2020, a hypothetical 1% increase in interest rates would result in a decline in the market value for the fixed income portfolio of approximately $62$71 million.
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, 20192020 and 2018,2019, 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, 2019,2020, 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, 20192020 and 2018,2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019,2020, 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, 2019,2020, 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, 2020,2021, 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 auditsaudit 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/Asset DispositionsRetirements - 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. As describedThe 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 Note 4, there are certainJune 2022.
In the event that (i) the ZEC program is overturned or is otherwise materially adversely modified through legal regulatory,process; (ii) the amount of ZEC payments that may be awarded or other terms and economic mattersconditions of the second ZEC eligibility period proposed by the BPU in its final decision differ from those of the markets in which these nuclearcurrent ZEC period; or (iii) any of the Salem 1, Salem 2 and Hope Creek plants operate, which, ifis not favorably resolved, would result inawarded ZEC payments by the BPU and does not otherwise experience a material financial change, PSEG takingPower has disclosed that it will take all necessary steps to retire all ofcease to operate these nuclear plants subsequent to the initial ZEC period at or prior to a scheduled refueling outage, which is significantly in advance of their currently estimated remaining
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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 nuclear plants’ 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.
•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.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.
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•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 - 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“superfund” site requiring environmental remediation and has identified certain potentially responsible partiesPotentially Responsible Parties (PRPs), including PSEG’s subsidiaries Public Service Electric and Gas Company (PSE&G) and PSEG Power.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
66
(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 PSE&GPSEG 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, 2019,2020, 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 PSE&G’sPSEG’s assessment that itPSE&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 allocableestimated share of the remediation cost, the environmental liability recorded, and the evaluation of future recovery of the regulatory asset recorded by PSE&G 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 the allocablePSEG’s estimated share of the estimated 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 management’s judgments and estimates associated withpublicly 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 estimatingmanagement’s estimate of the environmental liability.
•We evaluated the assumptions used by management to estimate the allocablePSEG’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, | ||
We have served as the Company's auditor since 1934.
67
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, 20192020 and 2018, and2019, 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, 2019,2020, 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, 20192020 and 2018,2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019,2020, 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.
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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.
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• 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, | ||
We have served as the Company's auditor since 1934.
70
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, 20192020 and 2018,2019, 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, 2019,2020, 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, 20192020 and 2018,2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019,2020, 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.
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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
72
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, | ||
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 | ||||||||||||||||||||
| Years Ended December 31, | ||||||||||||||
| 2019 | 2018 | 2017 | ||||||||||||
| OPERATING REVENUES | $ | 10,076 | $ | 9,696 | $ | 9,094 | ||||||||
| OPERATING EXPENSES | ||||||||||||||
| Energy Costs | 3,372 | 3,225 | 2,778 | |||||||||||
| Operation and Maintenance | 3,111 | 3,069 | 2,901 | |||||||||||
| Depreciation and Amortization | 1,248 | 1,158 | 1,986 | |||||||||||
| (Gain) Loss on Asset Dispositions | 402 | (54 | ) | — | ||||||||||
| Total Operating Expenses | 8,133 | 7,398 | 7,665 | |||||||||||
| OPERATING INCOME | 1,943 | 2,298 | 1,429 | |||||||||||
| Income from Equity Method Investments | 14 | 15 | 14 | |||||||||||
| Net Gains (Losses) on Trust Investments | 260 | (143 | ) | 134 | ||||||||||
| Other Income (Deductions) | 125 | 85 | 82 | |||||||||||
| Non-Operating Pension and OPEB Credits (Costs) | 177 | 76 | — | |||||||||||
| Interest Expense | (569 | ) | (476 | ) | (391 | ) | ||||||||
| INCOME BEFORE INCOME TAXES | 1,950 | 1,855 | 1,268 | |||||||||||
| Income Tax Benefit (Expense) | (257 | ) | (417 | ) | 306 | |||||||||
| NET INCOME | $ | 1,693 | $ | 1,438 | $ | 1,574 | ||||||||
| WEIGHTED AVERAGE COMMON SHARES OUTSTANDING: | ||||||||||||||
| BASIC | 504 | 504 | 505 | |||||||||||
| DILUTED | 507 | 507 | 507 | |||||||||||
| NET INCOME PER SHARE: | ||||||||||||||
| BASIC | $ | 3.35 | $ | 2.85 | $ | 3.12 | ||||||||
| DILUTED | $ | 3.33 | $ | 2.83 | $ | 3.10 | ||||||||
See Notes to Consolidated Financial Statements.
74
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Millions
| Years Ended December 31, | ||||||||||||||
| 2019 | 2018 | 2017 | ||||||||||||
| NET INCOME | $ | 1,693 | $ | 1,438 | $ | 1,574 | ||||||||
| Other Comprehensive Income (Loss), net of tax | ||||||||||||||
| Unrealized Gains (Losses) on Available-for-Sale Securities, net of tax (expense) benefit of $(26), $11 and $(37) for the years ended 2019, 2018 and 2017, respectively | 41 | (17 | ) | 44 | ||||||||||
| Unrealized Gains (Losses) on Cash Flow Hedges, net of tax (expense) benefit of $6, $1, and $1 for the years ended 2019, 2018 and 2017, respectively | (14 | ) | (1 | ) | (2 | ) | ||||||||
| Pension/OPEB adjustment, net of tax (expense) benefit of $18, $(18) and $(4) for the years ended 2019, 2018 and 2017, respectively | (58 | ) | 46 | (8 | ) | |||||||||
| Other Comprehensive Income (Loss), net of tax | (31 | ) | 28 | 34 | ||||||||||
| COMPREHENSIVE INCOME | $ | 1,662 | $ | 1,466 | $ | 1,608 | ||||||||
| 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.
75
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONSOLIDATED BALANCE SHEETS
Millions
| December 31, | |||||||||
| 2019 | 2018 | ||||||||
| ASSETS | |||||||||
| CURRENT ASSETS | |||||||||
| Cash and Cash Equivalents | $ | 147 | $ | 177 | |||||
| Accounts Receivable, net of allowances of $60 in 2019 and $63 in 2018 | 1,313 | 1,435 | |||||||
| Tax Receivable | 21 | 242 | |||||||
| Unbilled Revenues | 239 | 240 | |||||||
| Fuel | 310 | 331 | |||||||
| Materials and Supplies, net | 587 | 571 | |||||||
| Prepayments | 79 | 94 | |||||||
| Derivative Contracts | 113 | 11 | |||||||
| Regulatory Assets | 351 | 389 | |||||||
| Assets Held for Sale | 30 | — | |||||||
| Other | 41 | 17 | |||||||
| Total Current Assets | 3,231 | 3,507 | |||||||
| PROPERTY, PLANT AND EQUIPMENT | 45,944 | 44,201 | |||||||
| Less: Accumulated Depreciation and Amortization | (10,100 | ) | (9,838 | ) | |||||
| Net Property, Plant and Equipment | 35,844 | 34,363 | |||||||
| NONCURRENT ASSETS | |||||||||
| Regulatory Assets | 3,677 | 3,399 | |||||||
| Operating Lease Right-of-Use Assets | 282 | — | |||||||
| Long-Term Investments | 812 | 896 | |||||||
| Nuclear Decommissioning Trust (NDT) Fund | 2,216 | 1,878 | |||||||
| Long-Term Tax Receivable | 150 | — | |||||||
| Long-Term Receivable of Variable Interest Entity | 813 | 624 | |||||||
| Rabbi Trust Fund | 246 | 224 | |||||||
| Goodwill | — | 16 | |||||||
| Other Intangibles | 149 | 143 | |||||||
| Derivative Contracts | 24 | 1 | |||||||
| Other | 286 | 275 | |||||||
| Total Noncurrent Assets | 8,655 | 7,456 | |||||||
| TOTAL ASSETS | $ | 47,730 | $ | 45,326 | |||||
| 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 | 0 | 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 | 0 | 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.
76
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONSOLIDATED BALANCE SHEETS
Millions
| December 31, | |||||||||
| 2019 | 2018 | ||||||||
| LIABILITIES AND CAPITALIZATION | |||||||||
| CURRENT LIABILITIES | |||||||||
| Long-Term Debt Due Within One Year | $ | 1,365 | $ | 1,294 | |||||
| Commercial Paper and Loans | 1,115 | 1,016 | |||||||
| Accounts Payable | 1,358 | 1,451 | |||||||
| Derivative Contracts | 36 | 11 | |||||||
| Accrued Interest | 116 | 110 | |||||||
| Accrued Taxes | 41 | 26 | |||||||
| Clean Energy Program | 143 | 143 | |||||||
| Obligation to Return Cash Collateral | 119 | 136 | |||||||
| Regulatory Liabilities | 234 | 311 | |||||||
| Other | 520 | 437 | |||||||
| Total Current Liabilities | 5,047 | 4,935 | |||||||
| NONCURRENT LIABILITIES | |||||||||
| Deferred Income Taxes and Investment Tax Credits (ITC) | 6,256 | 5,713 | |||||||
| Regulatory Liabilities | 3,002 | 3,221 | |||||||
| Operating Leases | 273 | — | |||||||
| Asset Retirement Obligations | 1,087 | 1,063 | |||||||
| Other Postretirement Benefit (OPEB) Costs | 734 | 704 | |||||||
| OPEB Costs of Servco | 626 | 501 | |||||||
| Accrued Pension Costs | 952 | 791 | |||||||
| Accrued Pension Costs of Servco | 171 | 109 | |||||||
| Environmental Costs | 349 | 327 | |||||||
| Derivative Contracts | 1 | 4 | |||||||
| Long-Term Accrued Taxes | 182 | 181 | |||||||
| Other | 218 | 232 | |||||||
| Total Noncurrent Liabilities | 13,851 | 12,846 | |||||||
| COMMITMENTS AND CONTINGENT LIABILITIES (See Note 15) | |||||||||
| CAPITALIZATION | |||||||||
LONG-TERM DEBT | 13,743 | 13,168 | |||||||
| STOCKHOLDERS’ EQUITY | |||||||||
| Common Stock, no par, authorized 1,000 shares; issued, 2019 and 2018— 534 shares | 5,003 | 4,980 | |||||||
| Treasury Stock, at cost, 2019 and 2018—30 shares | (831 | ) | (808 | ) | |||||
| Retained Earnings | 11,406 | 10,582 | |||||||
| Accumulated Other Comprehensive Loss | (489 | ) | (377 | ) | |||||
| Total Stockholders’ Equity | 15,089 | 14,377 | |||||||
| Total Capitalization | 28,832 | 27,545 | |||||||
| TOTAL LIABILITIES AND CAPITALIZATION | $ | 47,730 | $ | 45,326 | |||||
| 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) | 0 | 0 | |||||||||||||||
| 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, | ||||||||||||||
| 2019 | 2018 | 2017 | ||||||||||||
| CASH FLOWS FROM OPERATING ACTIVITIES | ||||||||||||||
| Net Income | $ | 1,693 | $ | 1,438 | $ | 1,574 | ||||||||
| Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: | ||||||||||||||
| Depreciation and Amortization | 1,248 | 1,158 | 1,986 | |||||||||||
| Amortization of Nuclear Fuel | 178 | 187 | 199 | |||||||||||
| (Gain) Loss on Asset Dispositions | 402 | (54 | ) | — | ||||||||||
| Emission Allowances and Renewable Energy Credit (REC) Compliance Accrual | 108 | 97 | 103 | |||||||||||
| Provision for Deferred Income Taxes (Other than Leases) and ITC | 180 | 568 | (167 | ) | ||||||||||
| Non-Cash Employee Benefit Plan (Credits) Costs | (48 | ) | 70 | 89 | ||||||||||
| Leveraged Lease (Income) Loss, Adjusted for Rents Received and Deferred Taxes | (14 | ) | (149 | ) | (159 | ) | ||||||||
| Net (Gain) Loss on Lease Investments | 32 | 5 | 48 | |||||||||||
| Net Realized and Unrealized (Gains) Losses on Energy Contracts and Other Derivatives | (290 | ) | 116 | 188 | ||||||||||
| Cost of Removal | (108 | ) | (160 | ) | (107 | ) | ||||||||
| Net Change in Regulatory Assets and Liabilities | 25 | (153 | ) | (188 | ) | |||||||||
| Net (Gains) Losses and (Income) Expense from NDT Fund | (296 | ) | 98 | (156 | ) | |||||||||
| Net Change in Certain Current Assets and Liabilities: | ||||||||||||||
| Tax Receivable | 77 | 17 | 65 | |||||||||||
| Accrued Taxes | (9 | ) | (69 | ) | 16 | |||||||||
| Cash Collateral | 349 | (247 | ) | (90 | ) | |||||||||
| Other Current Assets and Liabilities | (145 | ) | 70 | (72 | ) | |||||||||
| Employee Benefit Plan Funding and Related Payments | (39 | ) | (101 | ) | (81 | ) | ||||||||
| Other | 36 | 22 | 12 | |||||||||||
| Net Cash Provided By (Used In) Operating Activities | 3,379 | 2,913 | 3,260 | |||||||||||
| CASH FLOWS FROM INVESTING ACTIVITIES | ||||||||||||||
| Additions to Property, Plant and Equipment | (3,166 | ) | �� | (3,912 | ) | (4,190 | ) | |||||||
| Purchase of Emissions Allowances and RECs | (98 | ) | (146 | ) | (117 | ) | ||||||||
| Proceeds from Sales of Trust Investments | 1,787 | 1,501 | 2,319 | |||||||||||
| Purchases of Trust Investments | (1,814 | ) | (1,473 | ) | (2,340 | ) | ||||||||
| Other | 146 | 114 | 72 | |||||||||||
| Net Cash Provided By (Used In) Investing Activities | (3,145 | ) | (3,916 | ) | (4,256 | ) | ||||||||
| CASH FLOWS FROM FINANCING ACTIVITIES | ||||||||||||||
| Net Change in Commercial Paper and Loans | 99 | 474 | 154 | |||||||||||
| Issuance of Long-Term Debt | 1,900 | 2,750 | 2,175 | |||||||||||
| Redemption of Long-Term Debt | (1,250 | ) | (1,350 | ) | (500 | ) | ||||||||
| Cash Dividends Paid on Common Stock | (950 | ) | (910 | ) | (870 | ) | ||||||||
| Other | (56 | ) | (77 | ) | (74 | ) | ||||||||
| Net Cash Provided By (Used In) Financing Activities | (257 | ) | 887 | 885 | ||||||||||
| Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash | (23 | ) | (116 | ) | (111 | ) | ||||||||
| Cash, Cash Equivalents and Restricted Cash at Beginning of Period | 199 | 315 | 426 | |||||||||||
| Cash, Cash Equivalents and Restricted Cash at End of Period | $ | 176 | $ | 199 | $ | 315 | ||||||||
| Supplemental Disclosure of Cash Flow Information: | ||||||||||||||
| Income Taxes Paid (Received) | $ | 41 | $ | 99 | $ | (8 | ) | |||||||
| Interest Paid, Net of Amounts Capitalized | $ | 539 | $ | 454 | $ | 377 | ||||||||
| Accrued Property, Plant and Equipment Expenditures | $ | 499 | $ | 517 | $ | 722 | ||||||||
| 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 | 0 | 0 | |||||||||||||||||||||||
| Repayment of Short-Term Loans | (500) | 0 | 0 | |||||||||||||||||||||||
| 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 January 1, 2017 | 534 | $ | 4,936 | (29 | ) | $ | (717 | ) | $ | 9,174 | $ | (263 | ) | $ | 13,130 | |||||||||||||
| Net Income | — | — | — | — | 1,574 | — | 1,574 | |||||||||||||||||||||
| Other Comprehensive Income (Loss), net of tax (expense) benefit of $(40) | — | — | — | — | — | 34 | 34 | |||||||||||||||||||||
| Comprehensive Income | 1,608 | |||||||||||||||||||||||||||
| Cash Dividends at $1.72 per share on Common Stock | — | — | — | — | (870 | ) | — | (870 | ) | |||||||||||||||||||
| Other | — | 25 | — | (46 | ) | — | — | (21 | ) | |||||||||||||||||||
| 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 from 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 | |||||||||||||
| 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) | 0 | (910) | |||||||||||||||||||||||||||||||||||||||||||
| Other | — | 19 | (1) | (45) | 0 | 0 | (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) | 0 | (950) | |||||||||||||||||||||||||||||||||||||||||||
| Other | 0 | 23 | 0 | (23) | 0 | 0 | 0 | |||||||||||||||||||||||||||||||||||||||||||
| 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) | 0 | (991) | |||||||||||||||||||||||||||||||||||||||||||
| Other | 0 | 28 | 0 | (30) | 0 | 0 | (2) | |||||||||||||||||||||||||||||||||||||||||||
| Balance as of December 31, 2020 | 534 | $ | 5,031 | (30) | $ | (861) | $ | 12,318 | $ | (504) | $ | 15,984 | ||||||||||||||||||||||||||||||||||||||
See Notes to Consolidated Financial Statements.
79
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
Millions
| Years Ended December 31, | ||||||||||||||
| 2019 | 2018 | 2017 | ||||||||||||
| OPERATING REVENUES | $ | 6,625 | $ | 6,471 | $ | 6,324 | ||||||||
| OPERATING EXPENSES | ||||||||||||||
| Energy Costs | 2,738 | 2,520 | 2,421 | |||||||||||
| Operation and Maintenance | 1,581 | 1,575 | 1,458 | |||||||||||
| Depreciation and Amortization | 837 | 770 | 685 | |||||||||||
| Total Operating Expenses | 5,156 | 4,865 | 4,564 | |||||||||||
| OPERATING INCOME | 1,469 | 1,606 | 1,760 | |||||||||||
| Net Gains (Losses) on Trust Investments | 2 | (1 | ) | 2 | ||||||||||
| Other Income (Deductions) | 83 | 80 | 85 | |||||||||||
| Non-Operating Pension and OPEB Credits (Costs) | 150 | 59 | (8 | ) | ||||||||||
| Interest Expense | (361 | ) | (333 | ) | (303 | ) | ||||||||
| INCOME BEFORE INCOME TAXES | 1,343 | 1,411 | 1,536 | |||||||||||
| Income Tax Expense | (93 | ) | (344 | ) | (563 | ) | ||||||||
| NET INCOME | $ | 1,250 | $ | 1,067 | $ | 973 | ||||||||
| 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) | 0 | 0 | |||||||||||||||||||||||
| 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.
80
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Millions
| Years Ended December 31, | ||||||||||||||
| 2019 | 2018 | 2017 | ||||||||||||
| NET INCOME | $ | 1,250 | $ | 1,067 | $ | 973 | ||||||||
| Other Comprehensive Income (Loss), net of tax | ||||||||||||||
| Unrealized Gains (Losses) on Available-for-Sale Securities, net of tax (expense) benefit of $(1), $1 and $0 for the years ended 2019, 2018 and 2017, respectively | 3 | (1 | ) | (1 | ) | |||||||||
| COMPREHENSIVE INCOME | $ | 1,253 | $ | 1,066 | $ | 972 | ||||||||
| 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.
81
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
CONSOLIDATED BALANCE SHEETS
Millions
| December 31, | |||||||||
| 2019 | 2018 | ||||||||
| ASSETS | |||||||||
| CURRENT ASSETS | |||||||||
| Cash and Cash Equivalents | $ | 21 | $ | 39 | |||||
| Accounts Receivable, net of allowances of $60 in 2019 and $63 in 2018 | 901 | 879 | |||||||
| Tax Receivable | — | 20 | |||||||
| Accounts Receivable—Affiliated Companies | 1 | 123 | |||||||
| Unbilled Revenues | 239 | 240 | |||||||
| Materials and Supplies, net | 213 | 196 | |||||||
| Prepayments | 35 | 10 | |||||||
| Regulatory Assets | 351 | 389 | |||||||
| Other | 28 | 11 | |||||||
| Total Current Assets | 1,789 | 1,907 | |||||||
| PROPERTY, PLANT AND EQUIPMENT | 33,900 | 31,633 | |||||||
| Less: Accumulated Depreciation and Amortization | (6,623 | ) | (6,277 | ) | |||||
| Net Property, Plant and Equipment | 27,277 | 25,356 | |||||||
| NONCURRENT ASSETS | |||||||||
| Regulatory Assets | 3,677 | 3,399 | |||||||
| Operating Lease Right-of-Use Assets | 98 | — | |||||||
| Long-Term Investments | 248 | 270 | |||||||
| Rabbi Trust Fund | 48 | 45 | |||||||
| Other | 129 | 132 | |||||||
| Total Noncurrent Assets | 4,200 | 3,846 | |||||||
| TOTAL ASSETS | $ | 33,266 | $ | 31,109 | |||||
| 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 | 0 | 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.
82
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
CONSOLIDATED BALANCE SHEETS
Millions
| December 31, | |||||||||
| 2019 | 2018 | ||||||||
| LIABILITIES AND CAPITALIZATION | |||||||||
| CURRENT LIABILITIES | |||||||||
| Long-Term Debt Due Within One Year | $ | 259 | $ | 500 | |||||
| Commercial Paper and Loans | 362 | 272 | |||||||
| Accounts Payable | 639 | 713 | |||||||
| Accounts Payable—Affiliated Companies | 390 | 321 | |||||||
| Accrued Interest | 91 | 84 | |||||||
| Clean Energy Program | 143 | 143 | |||||||
| Obligation to Return Cash Collateral | 119 | 136 | |||||||
| Regulatory Liabilities | 234 | 311 | |||||||
| Other | 436 | 345 | |||||||
| Total Current Liabilities | 2,673 | 2,825 | |||||||
| NONCURRENT LIABILITIES | |||||||||
| Deferred Income Taxes and ITC | 4,189 | 3,830 | |||||||
| Regulatory Liabilities | 3,002 | 3,221 | |||||||
| Operating Leases | 87 | — | |||||||
| Asset Retirement Obligations | 303 | 302 | |||||||
| OPEB Costs | 495 | 486 | |||||||
| Accrued Pension Costs | 501 | 400 | |||||||
| Environmental Costs | 294 | 268 | |||||||
| Long-Term Accrued Taxes | 115 | 69 | |||||||
| Other | 136 | 124 | |||||||
| Total Noncurrent Liabilities | 9,122 | 8,700 | |||||||
| COMMITMENTS AND CONTINGENT LIABILITIES (See Note 15) | |||||||||
| CAPITALIZATION | |||||||||
| LONG-TERM DEBT | 9,568 | 8,684 | |||||||
| STOCKHOLDER’S EQUITY | |||||||||
| Common Stock; 150 shares authorized; issued and outstanding, 2019 and 2018—132 shares | 892 | 892 | |||||||
| Contributed Capital | 1,095 | 1,095 | |||||||
| Basis Adjustment | 986 | 986 | |||||||
| Retained Earnings | 8,928 | 7,928 | |||||||
| Accumulated Other Comprehensive Income (Loss) | 2 | (1 | ) | ||||||
| Total Stockholder’s Equity | 11,903 | 10,900 | |||||||
| Total Capitalization | 21,471 | 19,584 | |||||||
| TOTAL LIABILITIES AND CAPITALIZATION | $ | 33,266 | $ | 31,109 | |||||
| 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) | 0 | 0 | |||||||||||||||
| 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, | ||||||||||||||
| 2019 | 2018 | 2017 | ||||||||||||
| CASH FLOWS FROM OPERATING ACTIVITIES | ||||||||||||||
| Net Income | $ | 1,250 | $ | 1,067 | $ | 973 | ||||||||
| Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: | ||||||||||||||
| Depreciation and Amortization | 837 | 770 | 685 | |||||||||||
| Provision for Deferred Income Taxes and ITC | (28 | ) | 405 | 616 | ||||||||||
| Non-Cash Employee Benefit Plan (Credits) Costs | (62 | ) | 37 | 50 | ||||||||||
| Cost of Removal | (108 | ) | (160 | ) | (107 | ) | ||||||||
| Net Change in Other Regulatory Assets and Liabilities | 25 | (153 | ) | (188 | ) | |||||||||
| Net Change in Certain Current Assets and Liabilities | ||||||||||||||
| Accounts Receivable and Unbilled Revenues | (18 | ) | 65 | (106 | ) | |||||||||
| Materials and Supplies | (14 | ) | 1 | (13 | ) | |||||||||
| Prepayments | (9 | ) | 14 | (35 | ) | |||||||||
| Accounts Payable | (59 | ) | 64 | 1 | ||||||||||
| Accounts Receivable/Payable—Affiliated Companies, net | 203 | (139 | ) | 101 | ||||||||||
| Other Current Assets and Liabilities | 62 | 5 | 15 | |||||||||||
| Employee Benefit Plan Funding and Related Payments | (21 | ) | (85 | ) | (68 | ) | ||||||||
| Other | (23 | ) | (38 | ) | (86 | ) | ||||||||
| Net Cash Provided By (Used In) Operating Activities | 2,035 | 1,853 | 1,838 | |||||||||||
| CASH FLOWS FROM INVESTING ACTIVITIES | ||||||||||||||
| Additions to Property, Plant and Equipment | (2,542 | ) | (2,896 | ) | (2,919 | ) | ||||||||
| Proceeds from Sales of Trust Investments | 36 | 20 | 36 | |||||||||||
| Purchases of Trust Investments | (34 | ) | (22 | ) | (37 | ) | ||||||||
| Solar Loan Investments | 8 | (5 | ) | 7 | ||||||||||
| Other | 10 | 9 | 10 | |||||||||||
| Net Cash Provided By (Used In) Investing Activities | (2,522 | ) | (2,894 | ) | (2,903 | ) | ||||||||
| CASH FLOWS FROM FINANCING ACTIVITIES | ||||||||||||||
| Net Change in Commercial Paper and Loans | 90 | 272 | — | |||||||||||
| Issuance of Long-Term Debt | 1,150 | 1,350 | 775 | |||||||||||
| Redemption of Long-Term Debt | (500 | ) | (750 | ) | — | |||||||||
| Contributed Capital | — | — | 150 | |||||||||||
| Cash Dividend Paid | (250 | ) | — | — | ||||||||||
| Other | (14 | ) | (14 | ) | (9 | ) | ||||||||
| Net Cash Provided By (Used In) Financing Activities | 476 | 858 | 916 | |||||||||||
| Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash | (11 | ) | (183 | ) | (149 | ) | ||||||||
| Cash, Cash Equivalents and Restricted Cash at Beginning of Period | 61 | 244 | 393 | |||||||||||
| Cash, Cash Equivalents and Restricted Cash at End of Period | $ | 50 | $ | 61 | $ | 244 | ||||||||
| Supplemental Disclosure of Cash Flow Information: | ||||||||||||||
| Income Taxes Paid (Received) | $ | (48 | ) | $ | 94 | $ | (104 | ) | ||||||
| Interest Paid, Net of Amounts Capitalized | $ | 343 | $ | 318 | $ | 294 | ||||||||
| Accrued Property, Plant and Equipment Expenditures | $ | 335 | $ | 350 | $ | 429 | ||||||||
| 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 | 0 | 0 | |||||||||||||||||||||||
| Cash Dividend Paid | (175) | (250) | 0 | |||||||||||||||||||||||
| 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.
84
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 January 1, 2017 | $ | 892 | $ | 945 | $ | 986 | $ | 5,888 | $ | 1 | $ | 8,712 | ||||||||||||||
| Net Income | — | — | — | 973 | — | 973 | ||||||||||||||||||||
| Other Comprehensive Income (Loss), net of tax (expense) benefit of $0 | — | — | — | — | (1 | ) | (1 | ) | ||||||||||||||||||
| Comprehensive Income | 972 | |||||||||||||||||||||||||
| Contributed Capital | — | 150 | — | — | — | 150 | ||||||||||||||||||||
| 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 | ||||||||||||||
| 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 | $ | 0 | $ | 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.
85
PSEG POWER LLC
CONSOLIDATED STATEMENTS OF OPERATIONS
Millions
| Years Ended December 31, | ||||||||||||||
| 2019 | 2018 | 2017 | ||||||||||||
| OPERATING REVENUES | $ | 4,385 | $ | 4,146 | $ | 3,860 | ||||||||
| OPERATING EXPENSES | ||||||||||||||
| Energy Costs | 2,118 | 2,197 | 1,913 | |||||||||||
| Operation and Maintenance | 1,040 | 1,053 | 1,046 | |||||||||||
| Depreciation and Amortization | 377 | 354 | 1,268 | |||||||||||
| (Gain) Loss on Asset Dispositions | 402 | (54 | ) | — | ||||||||||
| Total Operating Expenses | 3,937 | 3,550 | 4,227 | |||||||||||
| OPERATING INCOME (LOSS) | 448 | 596 | (367 | ) | ||||||||||
| Income from Equity Method Investments | 14 | 15 | 14 | |||||||||||
| Net Gains (Losses) on Trust Investments | 253 | (140 | ) | 125 | ||||||||||
| Other Income (Deductions) | 54 | 21 | 20 | |||||||||||
| Non-Operating Pension and OPEB (Costs) Credits | 21 | 15 | 8 | |||||||||||
| Interest Expense | (119 | ) | (76 | ) | (50 | ) | ||||||||
| INCOME (LOSS) BEFORE INCOME TAXES | 671 | 431 | (250 | ) | ||||||||||
| Income Tax Benefit (Expense) | (203 | ) | (66 | ) | 729 | |||||||||
| NET INCOME | $ | 468 | $ | 365 | $ | 479 | ||||||||
| 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.
86
PSEG POWER LLC
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Millions
| Years Ended December 31, | ||||||||||||||
| 2019 | 2018 | 2017 | ||||||||||||
| NET INCOME | $ | 468 | $ | 365 | $ | 479 | ||||||||
| Other Comprehensive Income (Loss), net of tax | ||||||||||||||
| Unrealized Gains (Losses) on Available-for-Sale Securities, net of tax (expense) benefit of $(22), $9, and $(39) for the years ended 2019, 2018 and 2017, respectively | 32 | (13 | ) | 46 | ||||||||||
| Pension/OPEB adjustment, net of tax (expense) benefit of $13, $(16) and $(3) for the years ended 2019, 2018 and 2017, respectively | (45 | ) | 41 | (7 | ) | |||||||||
| Other Comprehensive Income (Loss), net of tax | (13 | ) | 28 | 39 | ||||||||||
| COMPREHENSIVE INCOME | $ | 455 | $ | 393 | $ | 518 | ||||||||
| 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.
87
PSEG POWER LLC
CONSOLIDATED BALANCE SHEETS
Millions
| December 31, | |||||||||
| 2019 | 2018 | ||||||||
| ASSETS | |||||||||
| CURRENT ASSETS | |||||||||
| Cash and Cash Equivalents | $ | 21 | $ | 22 | |||||
| Accounts Receivable | 309 | 477 | |||||||
| Accounts Receivable—Affiliated Companies | 408 | 274 | |||||||
| Short-Term Loan to Affiliate | 149 | — | |||||||
| Fuel | 310 | 331 | |||||||
| Materials and Supplies, net | 372 | 373 | |||||||
| Derivative Contracts | 113 | 11 | |||||||
| Prepayments | 11 | 14 | |||||||
| Assets Held for Sale | 28 | — | |||||||
| Other | 5 | 5 | |||||||
| Total Current Assets | 1,726 | 1,507 | |||||||
| PROPERTY, PLANT AND EQUIPMENT | 11,699 | 12,224 | |||||||
| Less: Accumulated Depreciation and Amortization | (3,273 | ) | (3,382 | ) | |||||
| Net Property, Plant and Equipment | 8,426 | 8,842 | |||||||
| NONCURRENT ASSETS | |||||||||
| Operating Lease Right-of-Use Assets | 71 | — | |||||||
| NDT Fund | 2,216 | 1,878 | |||||||
| Long-Term Investments | 66 | 86 | |||||||
| Goodwill | — | 16 | |||||||
| Other Intangibles | 149 | 143 | |||||||
| Rabbi Trust Fund | 62 | 56 | |||||||
| Derivative Contracts | 24 | 1 | |||||||
| Other | 65 | 65 | |||||||
| Total Noncurrent Assets | 2,653 | 2,245 | |||||||
| TOTAL ASSETS | $ | 12,805 | $ | 12,594 | |||||
| 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 | 0 | 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.
88
PSEG POWER LLC
CONSOLIDATED BALANCE SHEETS
Millions
| December 31, | |||||||||
| 2019 | 2018 | ||||||||
| LIABILITIES AND MEMBER’S EQUITY | |||||||||
| CURRENT LIABILITIES | |||||||||
| Long-Term Debt Due Within One Year | $ | 406 | $ | 44 | |||||
| Accounts Payable | 505 | 498 | |||||||
| Accounts Payable—Affiliated Companies | 5 | 16 | |||||||
| Short-Term Loan from Affiliate | — | 193 | |||||||
| Derivative Contracts | 31 | 11 | |||||||
| Accrued Interest | 21 | 21 | |||||||
| Other | 91 | 59 | |||||||
| Total Current Liabilities | 1,059 | 842 | |||||||
| NONCURRENT LIABILITIES | |||||||||
| Deferred Income Taxes and ITC | 1,876 | 1,619 | |||||||
| Operating Leases | 62 | — | |||||||
| Asset Retirement Obligations | 781 | 758 | |||||||
| OPEB Costs | 192 | 176 | |||||||
| Accrued Pension Costs | 284 | 246 | |||||||
| Derivative Contracts | 1 | 4 | |||||||
| Long-Term Accrued Taxes | 115 | 76 | |||||||
| Other | 111 | 122 | |||||||
| Total Noncurrent Liabilities | 3,422 | 3,001 | |||||||
| COMMITMENTS AND CONTINGENT LIABILITIES (See Note 15) | |||||||||
LONG-TERM DEBT | 2,434 | 2,791 | |||||||
| MEMBER’S EQUITY | |||||||||
| Contributed Capital | 2,214 | 2,214 | |||||||
| Basis Adjustment | (986 | ) | (986 | ) | |||||
| Retained Earnings | 5,063 | 5,051 | |||||||
| Accumulated Other Comprehensive Loss | (401 | ) | (319 | ) | |||||
| Total Member’s Equity | 5,890 | 5,960 | |||||||
| TOTAL LIABILITIES AND MEMBER’S EQUITY | $ | 12,805 | $ | 12,594 | |||||
| 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) | 0 | 0 | |||||||||||||||
| 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.
89
PSEG POWER LLC
CONSOLIDATED STATEMENTS OF CASH FLOWS
Millions
| Years Ended December 31, | ||||||||||||||
| 2019 | 2018 | 2017 | ||||||||||||
| CASH FLOWS FROM OPERATING ACTIVITIES | ||||||||||||||
| Net Income | $ | 468 | $ | 365 | $ | 479 | ||||||||
| Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: | ||||||||||||||
| Depreciation and Amortization | 377 | 354 | 1,268 | |||||||||||
| Amortization of Nuclear Fuel | 178 | 187 | 199 | |||||||||||
| (Gain) Loss on Asset Dispositions | 402 | (54 | ) | — | ||||||||||
| Emission Allowances and Renewable Energy Credit (REC) Compliance Accrual | 108 | 97 | 103 | |||||||||||
| Provision for Deferred Income Taxes and ITC | 248 | 206 | (807 | ) | ||||||||||
| Non-Cash Employee Benefit Plan Costs | 7 | 23 | 28 | |||||||||||
| Interest Accretion on Asset Retirement Obligation | 40 | 41 | 30 | |||||||||||
| Net Realized and Unrealized (Gains) Losses on Energy Contracts and Other Derivatives | (290 | ) | 116 | 188 | ||||||||||
| Net (Gains) Losses and (Income) Expense from NDT Fund | (296 | ) | 98 | (156 | ) | |||||||||
| Net Change in Certain Current Assets and Liabilities | ||||||||||||||
| Fuel, Materials and Supplies | (1 | ) | (39 | ) | 42 | |||||||||
| Cash Collateral | 349 | (247 | ) | (90 | ) | |||||||||
| Accounts Receivable | (32 | ) | 51 | (45 | ) | |||||||||
| Accounts Payable | 5 | (13 | ) | 39 | ||||||||||
| Accounts Receivable/Payable—Affiliated Companies, net | (112 | ) | (56 | ) | (2 | ) | ||||||||
| Other Current Assets and Liabilities | 14 | (40 | ) | 10 | ||||||||||
| Employee Benefit Plan Funding and Related Payments | (11 | ) | (9 | ) | (7 | ) | ||||||||
| Other | 25 | 4 | 47 | |||||||||||
| Net Cash Provided By (Used In) Operating Activities | 1,479 | 1,084 | 1,326 | |||||||||||
| CASH FLOWS FROM INVESTING ACTIVITIES | ||||||||||||||
| Additions to Property, Plant and Equipment | (607 | ) | (996 | ) | (1,231 | ) | ||||||||
| Purchase of Emissions Allowances and RECs | (98 | ) | (146 | ) | (117 | ) | ||||||||
| Proceeds from Sales of Trust Investments | 1,658 | 1,423 | 2,182 | |||||||||||
| Purchases of Trust Investments | (1,685 | ) | (1,392 | ) | (2,199 | ) | ||||||||
| Short-Term Loan to Affiliate | (149 | ) | — | 87 | ||||||||||
| Other | 120 | 60 | 46 | |||||||||||
| Net Cash Provided By (Used In) Investing Activities | (761 | ) | (1,051 | ) | (1,232 | ) | ||||||||
| CASH FLOWS FROM FINANCING ACTIVITIES | ||||||||||||||
| Issuance of Long-Term Debt | — | 700 | — | |||||||||||
| Cash Dividend Paid | (525 | ) | (400 | ) | (350 | ) | ||||||||
| Redemption of Long-Term Debt | — | (250 | ) | — | ||||||||||
| Short-Term Loan from Affiliate | (193 | ) | (88 | ) | 281 | |||||||||
| Other | (1 | ) | (5 | ) | (4 | ) | ||||||||
| Net Cash Provided By (Used In) Financing Activities | (719 | ) | (43 | ) | (73 | ) | ||||||||
| Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash | (1 | ) | (10 | ) | 21 | |||||||||
| Cash, Cash Equivalents and Restricted Cash at Beginning of Period | 22 | 32 | 11 | |||||||||||
| Cash, Cash Equivalents and Restricted Cash at End of Period | $ | 21 | $ | 22 | $ | 32 | ||||||||
| Supplemental Disclosure of Cash Flow Information: | ||||||||||||||
| Income Taxes Paid (Received) | $ | (41 | ) | $ | (92 | ) | $ | 77 | ||||||
| Interest Paid, Net of Amounts Capitalized | $ | 113 | $ | 73 | $ | 48 | ||||||||
| Accrued Property, Plant and Equipment Expenditures | $ | 164 | $ | 167 | $ | 293 | ||||||||
| 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) | 0 | |||||||||||||||||||||||
| 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 | 0 | 0 | 700 | |||||||||||||||||||||||
| Cash Dividend Paid | (350) | (525) | (400) | |||||||||||||||||||||||
| Redemption of Long-Term Debt | (406) | 0 | (250) | |||||||||||||||||||||||
| Short-Term Loan from Affiliate | 0 | (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.
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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 January 1, 2017 | $ | 2,214 | $ | (986 | ) | $ | 4,782 | $ | (211 | ) | $ | 5,799 | ||||||||||
| Net Income | — | — | 479 | — | 479 | |||||||||||||||||
| Other Comprehensive Income (Loss), net of tax (expense) benefit of $(42) | — | — | — | 39 | 39 | |||||||||||||||||
| Comprehensive Income | 518 | |||||||||||||||||||||
| Cash Dividends Paid | — | — | (350 | ) | — | (350 | ) | |||||||||||||||
| 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 | ||||||||||
| 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.
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 primarily hasearns it revenues from its portfolio of lease investments and holds our investment in leveraged leases;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
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December 31, 20182019 and 2019.2020. 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 | 0 | 0 | 11 | |||||||||||||||||||||||||
| Restricted Cash in Other Noncurrent Assets | 18 | 0 | 0 | 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 | 0 | 0 | 7 | |||||||||||||||||||||||||
| Restricted Cash in Other Noncurrent Assets | 22 | 0 | 0 | 22 | |||||||||||||||||||||||||
| Cash, Cash Equivalents and Restricted Cash | $ | 233 | $ | 27 | $ | 312 | $ | 572 | |||||||||||||||||||||
(A)Includes amounts applicable to PSEG (parent company), Energy Holdings and Services.
| PSE&G | PSEG Power | Other (A) | Consolidated | ||||||||||||||
| Millions | |||||||||||||||||
| As of December 31, 2018 | |||||||||||||||||
| Cash and Cash Equivalents | $ | 39 | $ | 22 | $ | 116 | $ | 177 | |||||||||
| Restricted Cash in Other Current Assets | 8 | — | — | 8 | |||||||||||||
| Restricted Cash in Other Noncurrent Assets | 14 | — | — | 14 | |||||||||||||
| Cash, Cash Equivalents and Restricted Cash | $ | 61 | $ | 22 | $ | 116 | $ | 199 | |||||||||
| 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 | |||||||||
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
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:
| 2019 | 2018 | 2017 | |||||||||
| Avg Rate | Avg Rate | Avg Rate | |||||||||
| Electric Transmission | 2.41 | % | 2.42 | % | 2.41 | % | |||||
| Electric Distribution | 2.54 | % | 2.51 | % | 2.51 | % | |||||
| Gas Distribution | 1.85 | % | 1.61 | % | 1.63 | % | |||||
| 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, 2018 and 20172018 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
| AFUDC/IDC Capitalized | |||||||||||||||||||||||
| 2019 | 2018 | 2017 | |||||||||||||||||||||
| Millions | Avg Rate | Millions | Avg Rate | Millions | Avg Rate | ||||||||||||||||||
| PSE&G | $ | 81 | 7.22 | % | $ | 70 | 7.74 | % | $ | 73 | 7.42 | % | |||||||||||
| PSEG Power | $ | 27 | 4.60 | % | $ | 67 | 4.60 | % | $ | 78 | 4.60 | % | |||||||||||
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. See Note 4. Early Plant Retirements/Asset Dispositions for more information.
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 plantsunits 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 Doubtful AccountsCredit 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 doubtful accounts.an allowance for credit losses. The allowance for doubtful accountscredit losses reflects PSE&G’s best estimatesestimate of losses on the accounts receivableaccount balances. The allowance is based on PSE&G’s projection of accounts receivable aging, historical experience, write-off forecastseconomic factors and other currently available evidence.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
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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 whichthat increase the capacity, improve or extend the life of an existing asset,asset; represent a newly acquired or constructed assetasset; 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. See Note 2. Recent Accounting Standards for additional information.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.
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PSEG and its subsidiaries, have lease agreements with lease and non-lease components, which are primarily related to real estate assets anddomestic energy generation including solar generatinggeneration facilities. PSEG and subsidiaries account for the lease and non-lease components as a single lease component.
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.
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 isare 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$986 million,, net of tax, was recorded as a Basis Adjustment on PSE&G’s and PSEG Power’s Consolidated Balance Sheets. The $986$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 20192020
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 related updates, replace existing lease accounting guidance and require lessees to recognize leasessupportable forecasts over a reasonable period. For purchased financial assets with credit deterioration, a term greater than 12 months on the balance sheet using a right-of-use asset approach. At lease commencement, a lessee will recognize a lease asset and corresponding lease obligation. A lessee will classify its leases as either finance leases or operating leases and a lessor will classify its leases as operating leases, direct financing leases, or sales-type leases. The standard requires additional disclosure of key information. Existing guidance related to leveraged leases does not change.
The impact of adoption on PSEG’s Consolidated Balance Sheetstandard was to record Operating Lease Right-of-Use Assets of $261 millioneffective for annual and Operating Lease Liabilities of $282 million. As part of that impact, PSEG reclassified deferred rent incentives and deferred rent liabilities of approximately $21 million, which were previously classified as Other Noncurrent Liabilities, to Operating Lease Right-of-Use Assets in accordance with this standard. PSE&G’s assets and liabilities each increased by $91 million and PSEG Power’s assets and liabilities each increased by $46 million. PSEG’s adoption of this standard did not have a material impact on the Consolidated Statements of Operations or Consolidated Statements of Cash Flows of PSEG, PSE&G and PSEG Power. See Note 8. Leases for additional information.
interim periods beginning after December 15, 2019. PSEG adopted this standard on January 1, 2019. The standard requires using2020 on a modified retrospective method upon adoption. PSEG analyzed thebasis. 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 its consolidatedthe 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 determined thattransfers 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 could enablehave 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 to enter into certain transactions that can be deemed hedges that previously would not have qualified.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 Power.PSEG.
This accounting standard was issuedimproves 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 shorten the amortization perioddecision makers and service providers are variable interests.
This standard is effective for certain callable debt securities held at a premium. Specifically, theannual and interim periods beginning after December 15, 2019. The standard requires the premiumis required to be amortizedapplied retrospectively with a cumulative effect adjustment to Retained Earnings at the beginning of the earliest call date.
period presented. PSEG adopted this standard on January 1, 2019 on a modified retrospective basis through a cumulative effect adjustment directly to Retained Earnings as of the beginning of 2019.2020. Adoption of this standard did not have a materialan 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 and disclosure of the nature of and reason for the change in accounting principle upon transition.basis. The new standard iswas effective for impairment tests for periods beginning January 1, 2020. Early adoption is permitted for interim or annual goodwill impairment tests performed on testing dates after January 1, 2017. PSEG early adopted this standard in the fourth quarter of 2019. See Note 12. Goodwill2019, and Other Intangibles.
This accounting standard provides a new modelclarification of guidance for recognizing credit losses on financial assets. The new model requires entitiesinstruments and makes narrow scope amendments related 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 to be based on past events, current conditions and supportable forecasts over a reasonable period. For purchased financial assets with credit deterioration, a similar model is to be used; however, the initial allowance will be added to the purchase price rather than reported as an allowance. Credit losses on available-for-sale debt securities will be measured in a manner similar to current GAAP; however, this standard requires those credit losses to 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.
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Facilitation of the Disclosure Requirements for Fair Value MeasurementEffects of Reference Rate Reform on Financial Reporting—ASU 2018-132020-04
This accounting standard modifies the disclosure requirementsprovides optional expedients and exceptions for fair value measurements. Certain current disclosure requirements relatingapplying GAAP to Level 3 fair value measurements,contract modifications and transfers between Level 1 and Level 2 fair value measurements willhedging relationships, subject to meeting certain criteria, that reference London Interbank Offered Rate (LIBOR) or another reference rate expected to be eliminated.discontinued. The standard will also add certain other disclosure requirements for Level 3 fair value measurements.
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. SeeTable of ContentsNote 14. Pension, Other Postretirement Benefits (OPEB) and Savings Plans.
Simplifying the Accounting for Income Taxes—ASU 2019-12
This accounting standard simplifiesupdates ASC 740 to simplify the accounting for income taxes, including the elimination of certainseveral exceptions and making other clarifications to the current requirements. Certain other requirementsguidance. Some of the more pertinent modifications include a change to the tax accounting related to franchise taxes that are partially based on income, step-upan election to allocate the consolidated tax expense to a disregarded entity that is a member of a consolidated tax basis of goodwillreturn filing group when those entities issue separate financial statements, and allocation of consolidated taxesmodifications and clarifications to legal entities have been added and certain clarifications were made to other requirements.interim tax reporting.
The standard is effective for fiscal years beginning after December 15, 2020 and early adoption is permitted. Certain amendments in this standardAmendments will be applied either on a retrospective, basis to all periods presented. Certain other amendments 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 ofin the beginning of the fiscal year of adoption. All other amendments will be appliedadoption, or on a prospective basis. PSEG is currently analyzingadopted this standard on January 1, 2021. PSEG will be electing to allocate the impactconsolidated 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 itsthe financial statements.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. UnderPSEG 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 prospective transition, PSEGcontract 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 apply the amendments atbe 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 interim period that includes thefiscal year of adoption. Early adoption date.is permitted. PSEG is currently analyzing the impactadopted this standard on January 1, 2021. Adoption of this standard did not have an impact on itsthe financial statements.statements of PSEG, PSE&G and PSEG Power.
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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 servicesservice(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
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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 month 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 ISOIndependent 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.
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Revenues Unrelated to Contracts with Customers
Energy Holdings generates lease revenues which are recorded pursuant to lease accounting guidance.
| PSE&G | PSEG Power | Other | Eliminations | Consolidated | |||||||||||||||||||||||||||||||
| Millions | |||||||||||||||||||||||||||||||||||
| Year Ended December 31, 2020 | |||||||||||||||||||||||||||||||||||
| Revenues from Contracts with Customers | |||||||||||||||||||||||||||||||||||
| Electric Distribution | $ | 3,130 | $ | 0 | $ | 0 | $ | 0 | $ | 3,130 | |||||||||||||||||||||||||
| Gas Distribution | 1,646 | 0 | 0 | (12) | 1,634 | ||||||||||||||||||||||||||||||
| Transmission | 1,485 | 0 | 0 | 0 | 1,485 | ||||||||||||||||||||||||||||||
| Electricity and Related Product Sales | |||||||||||||||||||||||||||||||||||
| PJM | |||||||||||||||||||||||||||||||||||
| Third-Party Sales | 0 | 1,551 | 0 | 0 | 1,551 | ||||||||||||||||||||||||||||||
| Sales to Affiliates | 0 | 447 | 0 | (447) | 0 | ||||||||||||||||||||||||||||||
| NY-ISO | 0 | 124 | 0 | 0 | 124 | ||||||||||||||||||||||||||||||
| ISO-NE | 0 | 126 | 0 | 0 | 126 | ||||||||||||||||||||||||||||||
| Gas Sales | |||||||||||||||||||||||||||||||||||
| Third-Party Sales | 0 | 83 | 0 | 0 | 83 | ||||||||||||||||||||||||||||||
| Sales to Affiliates | 0 | 771 | 0 | (771) | 0 | ||||||||||||||||||||||||||||||
| 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 | 0 | 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 | $ | 0 | $ | 0 | $ | 0 | $ | 3,224 | |||||||||||||||||||||||||
| Gas Distribution | 1,870 | 0 | 0 | (15) | 1,855 | ||||||||||||||||||||||||||||||
| Transmission | 1,181 | 0 | 0 | 0 | 1,181 | ||||||||||||||||||||||||||||||
| Electricity and Related Product Sales | |||||||||||||||||||||||||||||||||||
| PJM | |||||||||||||||||||||||||||||||||||
| Third-Party Sales | 0 | 1,785 | 0 | 0 | 1,785 | ||||||||||||||||||||||||||||||
| Sales to Affiliates | 0 | 536 | 0 | (536) | 0 | ||||||||||||||||||||||||||||||
| NY-ISO | 0 | 143 | 0 | 0 | 143 | ||||||||||||||||||||||||||||||
| ISO-NE | 0 | 137 | 0 | 0 | 137 | ||||||||||||||||||||||||||||||
| Gas Sales | |||||||||||||||||||||||||||||||||||
| Third-Party Sales | 0 | 92 | 0 | 0 | 92 | ||||||||||||||||||||||||||||||
| Sales to Affiliates | 0 | 927 | 0 | (927) | 0 | ||||||||||||||||||||||||||||||
| 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) | 0 | 768 | ||||||||||||||||||||||||||||||
| Total Operating Revenues | $ | 6,625 | $ | 4,385 | $ | 549 | $ | (1,483) | $ | 10,076 | |||||||||||||||||||||||||
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS