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 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 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; and PSEG Services Corporation (Services), which provides us and our operating subsidiaries with certain management, administrative and general services at cost.

The following is a more detailed description of our business, including a discussion of our:

•	Business Operations and Strategy

•	Competitive Environment

•	Employee Relations

•	Regulatory Issues

•	Environmental Matters

BUSINESS OPERATIONS AND STRATEGY

PSE&G

Our regulated T&D public utility, PSE&G, distributes electric energy and gas to customers within a designated service territory running diagonally across New Jersey where approximately 6.2 million people, or about 70% of New Jersey’s population resides.

Products and Services

Our utility operations primarily earn margins through the T&D of electricity and the distribution of gas.

•	Transmission—the movement of electricity at high voltage from generating plants to substations and transformers, where it is then reduced to a lower voltage for distribution to homes, businesses and industrial customers. Our

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revenues for these services are based upon tariffs approved by the Federal Energy Regulatory Commission (FERC).

•	Distribution—the delivery of electricity and gas to the retail customer’s home, business or industrial facility. Our revenues for these services are based upon tariffs approved by the New Jersey Board of Public Utilities (BPU).

The commodity portion of our utility business’ electric and gas sales is managed by basic generation service (BGS) and basic gas supply service (BGSS) suppliers. Pricing for those services is set by the BPU as a pass-through, resulting in no margin for our utility operations.

We also earn margins through competitive services, such as appliance repair, in our service territory.

In addition to our current utility products and services, we have implemented several programs to invest in regulated solar generation within New Jersey, including:

•	programs to help finance the installation of solar power systems throughout our electric service area, and

•	programs to develop, own and operate solar power systems.

We have also implemented a set of energy efficiency 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.

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 billion for transmission in 2020-2022 as disclosed in Item 7. MD&A—Capital Requirements.

Distribution

PSE&G distributes gas and electricity 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 and renewable energy investment programs with cost recovery through various clause mechanisms. Our load requirements are split among residential, commercial and industrial (C&I) customers, as described in the following table for 2019:

			% of 2019 Sales
	Customer Type		Electric		Gas
	Commercial		58%		38%
	Residential		33%		58%
	Industrial		9%		4%
	Total		100%		100%

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Our customer base has modestly increased since 2015, with electric and gas loads changing as illustrated below:

	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)%

(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 increases due to growth in the number of customers and improved economic conditions offset by conservation and more energy efficient appliances. Firm gas sales decreased slightly as a result of warmer weather in 2019 mostly offset by growth in the number of customers and customer response to continued low gas prices. Only firm gas sales impact margin.

In 2019, we commenced our BPU-approved Gas System Modernization Program 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.

In 2019, the BPU approved our Energy Strong Program II (ES II), 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 than December 2023.

In October 2018, we filed our proposed Clean Energy Future (CEF) program with the BPU, a six-year estimated $3.5 billion investment covering four programs: (i) an Energy Efficiency (EE) program designed to achieve energy efficiency targets required under 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, New Jersey released its Energy Master Plan 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 (a) extend several existing EE programs for six months, with an additional $111 million investment over the course of the programs, and (b) 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 proposed $1 billion investment in CEF-EC, CEF-EV and CEF-ES programs.

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% 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

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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.

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 seek 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.

Products and Services

As a merchant generator and power marketer, our profit 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 (kWh) or dollars per megawatt hour (MWh).

•	Capacity—distinct from energy, capacity is a market commitment that a given generation unit will be available to an Independent System Operator (ISO) for dispatch to produce energy when it is needed to meet system demand. Capacity is typically priced in dollars per MW for a given sale period (e.g. day or month).

•

Ancillary Services—related activities supplied by generation unit owners to the wholesale market that are required by the ISO to ensure the safe and reliable operation of the bulk power system. Owners of generation units may bid units into the ancillary services market in return for compensatory payments. Costs to pay generators for ancillary services are recovered through charges collected from market participants.

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•

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% 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.

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.

The map below shows the locations of our Northeast and Mid-Atlantic nuclear and fossil generation facilities:

•	Generation Capacity

Our nuclear and fossil installed capacity utilizes a diverse mix of fuels. As of December 31, 2019, our fuel mix was comprised of 56% gas, 34% nuclear, 3% coal, 5% oil and 2% pumped storage. This fuel diversity helps to mitigate risks associated with fuel price volatility and market demand cycles. Our total generating output in 2019 was approximately 56,800 gigawatt hours (GWh). In September 2019, PSEG Power completed the sale of its 776 MW ownership interests in the Keystone and Conemaugh generation plants in western Pennsylvania and related assets and liabilities. The sale in 2019 of PSEG Power’s ownership interests in Keystone and Conemaugh is the latest step in its move away from coal-fired generation. 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.

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The following table indicates the proportionate share of generating output by fuel type in 2019.

	Generation by Fuel Type (A)		Actual 2019
	Nuclear:
	New Jersey facilities		33%
	Pennsylvania facilities		20%
	Fossil:
	Natural Gas and Oil:
	New Jersey facilities		20%
	New York facilities		8%
	Maryland facilities		8%
	Connecticut facilities		4%
	Coal:
	Pennsylvania facilities		7%
	Connecticut Facilities		—%	(B)
	Total		100%

(A)	Excludes pumped storage, solar facilities and fossil generation in Hawaii which account for less than 2.2 percent of total generation.

(B) Less than one percent.

In June 2019, PSEG Power started commercial operation of Bridgeport Harbor Station Unit 5 (BH5), a 484 MW dual-fueled combined cycle generation station, completing its 1,800 MW combined cycle gas turbine construction program.

In July 2018, Exelon, co-owner of the Peach Bottom nuclear facilities in Pennsylvania, submitted a second 20-year license renewal application with the Nuclear Regulatory Commission (NRC) for Peach Bottom Units 2 and 3. It is anticipated that the NRC’s review process will take approximately 20-24 months from submission of the application. Peach Bottom Units 2 and 3 are currently licensed to operate through 2033 and 2034, respectively.

•	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. In 2019, the base load capacity factors for the following units were:

	Unit		2019 Capacity Factor
	Nuclear
	Salem Unit 1		76.4%
	Salem Unit 2		97.7%
	Hope Creek		82.5%
	Peach Bottom Unit 2		99.5%
	Peach Bottom Unit 3		92.8%

•

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

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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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Historical data implies that the price of natural gas will continue to have a strong influence on the price of electricity in the primary markets in which we operate.

The prices reflected in the preceding graphs above do not necessarily illustrate our contract prices, but they are representative of market prices at relatively liquid hubs, with nearer-term forward pricing generally resulting from more liquid markets than pricing for later years. As shown above, prices may vary by location resulting from congestion or other factors, such as the availability of natural gas from the Marcellus (Leidy) and other shale-gas regions. Purchases from the Marcellus/Utica shale gas regions in 2019 accounted for approximately 50% of the gas we procured. While these prices provide some perspective on past and future prices, the forward prices are volatile and there can be no assurance that such prices will remain in effect or that we will be able to contract output at these forward prices.

Fuel Supply

•	Nuclear Fuel Supply—We have long-term contracts for nuclear fuel. These contracts provide for:

•	purchase of uranium (concentrates and uranium hexafluoride),

•	conversion of uranium concentrates to uranium hexafluoride,

•	enrichment of uranium hexafluoride, and

•	fabrication of nuclear fuel assemblies.

•

Gas Supply—Natural gas is the primary fuel for the bulk of our load following and peaking fleet. We purchase gas directly from natural gas producers and marketers. These supplies are transported to New Jersey by four interstate pipelines with which we have contracted. In addition, we have firm gas transportation contracted for this winter season to serve a portion of the gas requirements for our Bethlehem Energy Center (BEC) in New York and hold year-round firm gas transportation to serve the majority of the requirements of Keys 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.

PSEG Power has contracted for approximately 125,000 dekatherms/day of delivery capability on the PennEast Pipeline from eastern Pennsylvania to New Jersey. This delivery capability will be used to supplement the BGSS contract when it becomes operational.

•	Oil—Oil is used as the primary fuel for one load following steam unit and four combustion turbine peaking units and can be used as an alternate fuel by several load following and peaking units that have a dual-fuel capability. Oil for

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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 2019 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. It serves over 65 million people, nearly 20% of the total United States population, and has a record peak demand of 165,492 MW. 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. This service area has a population of about 20 million and a record peak demand of 33,956 MW. 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. This service area has a population of about 15 million and a record peak demand of 28,130 MW. Our Bridgeport and New Haven stations operate in Connecticut.

The price of electricity varies by location in each of these markets. Depending on our production and our obligations, these price differentials may increase or decrease our profitability.

Commodity prices, such as electricity, gas, oil and environmental products, as well as the availability of our diverse fleet of generation units to operate, also have a considerable effect on our profitability. Over the long-term, the higher the forward prices are, the more attractive an environment exists for us to contract for the sale of our anticipated output. However, higher prices also increase the cost of replacement power; thereby placing us at greater risk should our generating units fail to operate effectively or otherwise become unavailable.

Over the past several years, lower wholesale natural gas prices have resulted in lower electric energy prices. 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 areas of these markets, there are transmission system transfer limitations which raise concerns about reliability and create a more acute need for capacity.

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

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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 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 and New England capacity through May 2026 for BH5 and May 2023 for New Haven through the RPM and FCM pricing mechanisms, respectively.

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.

On a prospective basis, many factors may affect the capacity pricing, including but not limited to:

•	load and demand,

•	availability of generating capacity (including retirements, additions, derates and forced outage rates),

•	capacity imports from external regions,

•	transmission capability between zones,

•	available amounts of demand response resources,

•	pricing mechanisms, including potentially increasing the number of zones to create more pricing sensitivity to changes in supply and demand, as well as other potential changes that PJM and the other ISOs may propose over time, and

•	legislative and/or regulatory actions impacting the capacity auction or that permit subsidized local electric power generation.

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 hedge our output are: (1) sales at PJM West or other nodes within PJM corresponding to our generation portfolio and (2) BGS and similar 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. 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.

In recent years, as market prices declined from previous levels, there was an incentive for more of the smaller C&I electric customers to switch to third-party suppliers. In a falling price environment, this has a negative impact on our margins, as the

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anticipated BGS pricing is replaced by lower spot market pricing. As average BGS rates have declined to a level that more closely resembles current market prices, customers may see less of an incentive to switch to third-party suppliers. We are unable to determine the degree to which this switching, or “migration,” will continue, but the impact on our results could be material should market prices fall or rise significantly.

Reflecting February 2020 BGS auction results, the contracted percentages of our anticipated base load generation output for the next three years with modest amounts beyond 2022 are as follows:

	Base Load Generation		2020		2021		2022
	Generation Sales		100%		80%-85%		30%-35%

In a changing market environment, this hedging strategy may cause our realized prices to differ materially from current market prices. In a rising price environment, this strategy normally results in lower margins than would have been the case had no hedging activity been conducted. Alternatively, in a falling price environment, this hedging strategy will tend to create margins higher than those implied by the then-current market.

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 2020 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.

Energy Holdings

Lease Investments

Energy Holdings primarily owns and manages a portfolio of domestic lease investments comprised principally of energy-related leveraged leases. See Item 8. Note 10. Financing Receivables for additional information.

Energy Holdings’ leveraged leasing portfolio is designed to provide a fixed rate of return. Leveraged lease investments involve three parties: an owner/lessor, a creditor and a lessee. In a typical leveraged lease financing, the lessor purchases an asset to be leased. The purchase price is typically financed 80% with debt provided by the creditor and the balance comes from equity funds provided by the lessor. The creditor provides long-term financing to the transaction secured by the property subject to the lease. Such long-term financing is non-recourse to the lessor and, with respect to our lease investments, is not presented on our Consolidated Balance Sheets.

The lessor acquires economic and tax ownership of the asset and then leases it to the lessee for a period of time no greater than 80% of its remaining useful life. As the owner, the lessor is entitled to depreciate the asset under applicable federal and state tax guidelines. The lessor receives income from lease payments made by the lessee during the term of the lease and from tax benefits associated with interest and depreciation deductions with respect to the leased property. Our ability to realize these tax benefits is dependent on operating gains generated by our other operating subsidiaries and allocated pursuant to the consolidated tax sharing agreement between us and our operating subsidiaries.

Lease rental payments are unconditional obligations of the lessee and are set at levels at least sufficient to service the non-recourse lease debt. The lessor is also entitled to any residual value associated with the leased asset at the end of the lease term. An evaluation of the after-tax cash flows to the lessor determines the return on the investment. Under accounting principles generally accepted in the United States (GAAP), the leveraged lease investment is recorded net of non-recourse debt and income is recognized as a constant return on the net unrecovered investment.

For additional information on leases, including the credit, tax and accounting risks, see Item 1A. Risk Factors, Item 7A. Quantitative and Qualitative Disclosures About Market Risk—Credit Risk, and Item 8. Note 10. Financing Receivables.

Offshore Wind

In June 2019, the BPU selected Ørsted US Offshore Wind’s Ocean Wind project as the winning bid in New Jersey’s initial

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solicitation for 1,100 MW of offshore wind generation. In October 2019, PSEG exercised its option on Ørsted’s Ocean Wind project, resulting in a period of exclusive negotiation for PSEG to potentially acquire a 25% equity interest in the project, subject to negotiations toward a joint venture agreement, advanced due diligence and any required regulatory approvals.

LIPA Operating Services Agreement (OSA)

In accordance with a twelve year Amended and Restated 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.

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 distribution 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.

Changes in the current policies for building new transmission lines, such as those ordered by FERC and being implemented by PJM and other ISOs to eliminate contractual provisions that previously provided us a “right of first refusal” to construct projects in our service territory, could result in third-party construction of transmission lines in our area in the future and also allow us to seek opportunities to build in other service territories. These rules continue to evolve so both the extent of the risk within our service territory and the opportunities for our transmission business elsewhere remain difficult to assess. For additional information, see the discussion in Regulatory Issues—Federal Regulation—Transmission Regulation, below.

PSEG Power

Various market participants compete with us and one another in transacting in the wholesale energy markets, entering into bilateral contracts and selling to individual and aggregated retail customers. Our competitors include:

•	merchant generators,

•	domestic and multi-national utility generators,

•	energy marketers and retailers,

•	private equity firms, banks and other financial entities,

•	fuel supply companies, and

•	affiliates of other industrial companies.

New additions of lower-cost or more efficient generation capacity, as well as subsidized generation capacity, could make our plants less economic in the future. Such capacity could impact market prices and our competitiveness.

Our business is also under competitive pressure due to demand-side management (DSM) and other efficiency efforts aimed at changing the quantity and patterns of usage by consumers which could result in a reduction in load requirements. A reduction in load requirements can also be caused by economic cycles, weather and climate change, municipal aggregation and other customer migration and other factors. In addition, how resources such as demand response (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

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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.

EMPLOYEE RELATIONS

As of December 31, 2019, we had 12,992 employees within our subsidiaries, including 8,001 covered under collective bargaining agreements expiring from 2021 through 2023 with eight unions. We believe we maintain satisfactory relationships with our employees.

	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

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 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 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.

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For us, the major effects of FERC regulation fall into five general categories:

•	Regulation of Wholesale Sales—Generation/Market Issues/Market Power

•	Energy Clearing Prices

•	Capacity Market Issues

•	Transmission Regulation

•	Compliance

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 following 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 nonperformance 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.

FERC has also ordered certain favorable changes to energy market price formation rules improving shortage pricing and enhancing bidding flexibility for units. We continue to advocate in this context for additional changes in market rules that would provide more transparency regarding operator actions affecting energy market prices and would promote better alignment between generation dispatch decisions and energy market price outcomes. Certain reforms, such as a reform that would allow prices to better reflect scarcity conditions in which short-term demand is met by fast-start resources, are currently pending before FERC. However, we cannot predict whether they will be adopted.

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. The new rules will not be implemented until FERC issues an order approving them. We will continue to participate in this process before FERC.

In March 2019, PJM filed a 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, these reforms are expected to improve energy and reserve prices by ensuring that when operators commit resources to ensure reliability, the commitments are reflected 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.

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. Maryland and Delaware are members of RGGI and other states, such as Virginia and Pennsylvania, continue 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

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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 and if it leads to a market solution, could have a material impact on the value of PSEG Power’s generating fleet.

Capacity Market Issues

PJM, NYISO and ISO-NE each have capacity markets that have been approved by FERC. FERC regulates these markets and continues to examine whether the market design for each of these three capacity markets is working optimally. Various forums are considering how the competitive market framework can incorporate or be reconciled with state public policies that support particular resources, resource attributes or emerging technologies, whether generators are being sufficiently compensated in the capacity market and whether subsidized resources may be adversely affecting capacity market prices. We cannot predict what action, if any, FERC might take with regard to capacity market designs.

PJM—The RPM is the locational installed capacity market design for the PJM region, including a forward auction for installed capacity. Under the RPM, generators located in constrained areas within PJM are paid more for their capacity as an incentive to ensure adequate supply where generation capacity is most needed. The mechanics of the RPM in PJM continue to evolve and be refined in stakeholder proceedings and FERC proceedings in which we are active.

In December 2019, FERC issued an order establishing new rules for PJM’s capacity market. In this new order, FERC extended the PJM Minimum Offer Price Rule (MOPR), which currently applies to new natural gas-fired generators, to include both new and existing resources that receive or are entitled to receive, certain out-of-market payments, with certain exemptions. The exemptions 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 exemption to the MOPR which would allow entities to demonstrate to the market monitor that they should be able to bid at a level below the generic MOPR offer floor. PSEG cannot at this time estimate the impact 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.

States that have clean energy programs designed to achieve public policy goals are not prevented from pursuing those programs by the expanded MOPR and could choose to utilize the existing Fixed Resource Requirement (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.

PSEG Power’s New Jersey nuclear plants that receive ZEC payments will be subject to the new MOPR. However, the impact (if any) of the MOPR on the ability of the nuclear plants to clear in RPM markets will depend on the level of the applicable generic offer floors, as well as the offer floor levels that would be derived via the unit specific exception, should one or more of the units elect that option. In addition, if one or more electric distribution zones in New Jersey (or another state) were to become 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 what impact those rules will have on the capacity market or our generating stations.

In October 2018, PJM filed with FERC to revise the shape of the Variable Resource Requirement (VRR) curve that will be implemented in the next capacity auction. The VRR curve is the administratively determined demand curve that serves as one of the key elements for establishing the amount of generation capacity to be procured in the auction. PJM’s proposed tariff revisions will result in lower cost of new entry (CONE) values as compared to the currently effective VRR curve. PSEG protested PJM’s proposal on the grounds that it would result in understated prices for capacity relative to the cost of constructing a new reference generating unit and will result in prices that are unjust and unreasonable. In April 2019, FERC issued an Order approving PJM’s filing without modification and these changes are expected to be in place for the 2022/2023 PJM capacity auction. In mid-May 2019, PSEG filed a request for rehearing which remains pending before FERC.

ISO-NE—ISO-NE’s market for installed capacity in New England provides fixed capacity payments for generators, imports and DR. 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.

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One capacity market matter pending before FERC involves rules to govern payments and bidding requirements for generators proposing to exit the market but required to remain in service for reliability reasons. In March 2015, FERC issued an order which held that units receiving special reliability payments could properly take those payments into account in formulating capacity market bids. We believe that this ruling could impact efficient price formation in the capacity market and could artificially suppress capacity market outcomes. In April 2015, a trade association, Independent Power Producers of New York, Inc. (IPPNY) of which PSEG Power is a member, filed for rehearing by FERC of this ruling, which was denied by FERC at the end of 2017. In connection with this same proceeding, FERC required NYISO to submit a report addressing whether buyer-side mitigation measures are needed for new entry occurring in the “Rest of State” region and for uneconomic retention and repowering anywhere in the state. NYISO filed a report with FERC in December 2015 contending that these measures are not needed. The IPPNY has opposed NYISO’s contentions. The matter remains pending before FERC. In addition, in May 2015, the New York Public Service Commission and other New York agencies filed a complaint at FERC requesting certain exemptions from the NYISO rules that prevent capacity suppliers from submitting bids that are not market competitive. In October 2015, FERC granted in part, certain of the requested exemptions for renewable resources and resources being used by the owner for self-supply. The IPPNY has challenged NYISO’s proposed implementation of the newly required exemptions. This challenge is still pending.

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, 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 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.

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 Flow model and Capital Asset Pricing model 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 ROE complaints have been pending before FERC regarding the ISO New England Inc. Transmission Owners and utilities in other jurisdictions.

In parallel to these proceedings, and in light of declining interest rates and other market conditions, over the past few years, several companies have negotiated settlements that have resulted in reduced ROEs. We continue to analyze the potential impact of these methodologies and cannot predict the outcome of ongoing ROE proceedings. 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 be 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 could decide or be required to build additional redundancy into their systems. This standard will supplement 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 July 1, 2020. We are currently planning for compliance with the new standards which have imposed additional obligations and costs.

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Commodity Futures Trading Commission (CFTC)

In accordance with the Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act), the SEC and the CFTC are in the process of implementing a new regulatory framework for swaps and security-based swaps. The legislation was enacted to reduce systemic risk, increase transparency and promote market integrity within the financial system by providing for the registration and comprehensive regulation of swap dealers and by imposing recordkeeping, data reporting, margin and clearing requirements with respect to swaps. To implement the Dodd-Frank Act, the CFTC has engaged in a comprehensive rulemaking process and has issued a number of proposed and final rules addressing many of the key issues. We are currently subject to recordkeeping and data reporting requirements applicable to commercial end users. The CFTC has also re-proposed rules establishing position limits for trading in certain commodities, such as natural gas, and we will begin complying with these rules once they become final.

Nuclear

Nuclear Regulatory Commission (NRC)

Our operation of nuclear generating facilities is subject to comprehensive regulation by the NRC, a federal agency established to regulate nuclear activities to ensure the protection of public health and safety, as well as the 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. 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.

State Regulation

Since our operations are primarily located within New Jersey, our principal state regulator is the BPU, which oversees electric and natural gas distribution companies in New Jersey. We are also subject to various other states’ regulations due to our operations in those states.

Our New Jersey utility operations are subject to comprehensive regulation by the BPU including, among other matters, regulation of retail electric and gas distribution rates and service, the issuance and sale of certain types of securities and compliance matters. PSE&G’s participation in solar, demand response and energy efficiency programs is also regulated by the BPU, as the terms and conditions of these programs are approved by the BPU. BPU regulation can also have a direct or indirect impact on our power generation business as it relates to energy supply agreements and energy policy in New Jersey.

In addition to base rates, we recover certain costs or earn on certain investments pursuant to mechanisms known as adjustment clauses. These clauses permit the flow-through of costs to, or the recovery of investments from, customers related to specific programs, outside the context of base rate proceedings. Recovery of these costs or investments is subject to BPU approval for which we make periodic filings. Delays in the pass-through of costs or recovery of investments under these mechanisms could result in significant changes in cash flow.

New Jersey Energy Master Plan (EMP)—In January 2020, the State of New Jersey released its EMP. While the EMP does not have the force of law and does not impose any obligations on utilities, it outlines current expectations regarding the state’s role in the use, management, and development of energy. The EMP recognizes the goals of New Jersey’s Clean Energy Act of 2018 (the Clean Energy Act) of reducing electric and gas consumption by at least 2% and 0.75%, respectively. The EMP outlines several strategies, including statewide energy efficiency programs; expansion of renewable generation (solar and offshore wind), energy storage and other carbon-free technologies; preservation of existing nuclear generation; 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 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 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 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.

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Energy Efficiency Initiatives—In May 2018, the New Jersey governor signed legislation that requires the state’s electric and gas utilities to implement energy efficiency programs that are expected to achieve energy savings targets for electric and gas usage within five years of the utilities’ implementation of those BPU-approved energy efficiency programs. To meet these savings targets, energy usage reductions and peak demand reductions that result from utility and non-utility based programs and investments (including building code changes) will be counted. The initial targets are 2% of annual electric usage and 0.75% of annual gas usage with the targets then being reassessed periodically by the BPU. The legislation requires utilities to make filings with the BPU outlining their planned investments and proposed programs for cost-effectively achieving the targeted energy savings. These filings are also expected to address the utility’s return of and on those investments and recovery of lost revenues associated with the lower sales. Numerous stakeholders, including public utilities like PSE&G, are engaged in several stakeholder proceedings being conducted by the BPU Staff to establish the final policies, rules, and guidelines that will govern the conduct of these energy efficiency initiatives.

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—In July 2019, the state’s EDCs filed their annual proposal for the conduct of the February 2020 BGS auction covering electric supply for energy years 2021 through 2023. 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, 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 uncertainty 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 being collected from customers, but not paid to the BGS suppliers due to several unresolved proceedings at FERC, and directed Board Staff to work with the parties prior to the filing of the 2021 BGS Auction proposals.

New Jersey Solar Initiatives—Pursuant to New Jersey’s Clean Energy Act of 2018, the BPU was required to undertake several initiatives in connection with New Jersey’s solar energy market.

First, the BPU was required to establish a “Community Solar Energy Pilot Program,” permitting customers to participate in solar energy projects remotely located from their properties, and allowing for bill credits related to that participation. The BPU developed and issued those rules, which became effective in February 2019. The Board is currently engaged in a stakeholder process with the state’s EDCs and others regarding final establishment of the community solar pilot program.

The Clean Energy Act also requires that the BPU close the existing SREC program to new applications by no later than June 1, 2021, upon attaining 5.1% of New Jersey retail electric sales from solar; provide for an orderly transition to a new SREC program, and create the new program. In December 2019, 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. The BPU is continuing to work with the state’s EDCs to establish the mechanisms for implementing the TI 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 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.

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Our cybersecurity program is focused on the following areas:

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Governance—The Cybersecurity Council, which is comprised of members of senior management, meets regularly to discuss emerging cybersecurity issues; maintenance of a corporate cybersecurity scorecard that sets annual improvement targets to approximately 30 metrics; and publication of security practices. The Cybersecurity Council ensures that senior management, and ultimately the Board, is informed of all information required to exercise proper oversight over cybersecurity risks and that escalation procedures are followed to promptly inform senior management and the Board of significant cybersecurity incidents and risks.

•	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.

•	Incident Response Plans—Maintaining and updating incident response plans that address the life cycle of a cyber incident from a technical perspective (i.e., detection, response, and recovery), as well as data breach response (with a focus on external communication and legal compliance); and testing those plans (both internally and through external exercises).

•	Mobile Security—Deploying controls to prevent loss of data through mobile device channels.

PSEG also maintains physical security measures to protect its Operational Technology systems, consistent with a defense in depth and risk-tiered approach. Such physical security measures may include access control systems, video surveillance, around-the-clock command center monitoring, and physical barriers (such as fencing, walls, and bollards). Additional features of PSEG’s physical security program include threat intelligence, insider threat mitigation, background checks, a threat level advisory system, a business interruption management model, and active coordination with federal, state, and local law enforcement officials. See Regulatory Issues—Federal for a discussion on physical reliability standards that the NERC has promulgated.

In addition, we are subject to federal and state requirements designed to further protect against cybersecurity threats to critical infrastructure, as discussed below. For a discussion of the risks associated with cybersecurity threats, see Item 1A. Risk Factors.

F****ederal—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 CIP 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 these supply chain risk management standards in October 2018, with an implementation date of July 1, 2020. We are taking steps to meet these additional obligations. Compliance with these new standards would be expected to impose additional costs.

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 law 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.

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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 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 CAA 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.

Climate Change

CO****2 Regulation under the CAA—In June 2019, the EPA issued its final Affordable Clean Energy (ACE) rule as a replacement for the repealed Clean Power Plan, a greenhouse gas emission regulation for existing power plants. The ACE rule narrowly defines the “best system of emissions reductions” (BSER) as heat improvements to be applied only to an individual unit, excluding other potential mechanisms to address climate change. In September 2019, a coalition of power companies, including PSEG, filed a Petition for Review of the ACE Rule with the D.C. Circuit challenging the EPA’s narrow interpretation of BSER. We cannot estimate the impact of this action on our business or results of operations.

Regional Greenhouse Gas Initiative (RGGI)—In response to concerns over global climate change, some states have developed initiatives to stimulate national climate legislation through CO2 emission reductions in the electric power industry.

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 allowances that are each equal to one ton of CO2 emissions. Generators are required to submit an allowance for each ton emitted over a three-year period. Allowances are available through the auction or secondary markets. 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) 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 proceeds will be allocated among the New Jersey Economic Development Authority (NJEDA), the BPU and the NJDEP. The state has issued a draft three-year Strategic Funding Plan and has announced that a final plan is expected to be issued prior to the allocation of proceeds in April 2020 from the 2020 auction. 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.

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Water Pollution Control

The Federal Water Pollution Control Act (FWPCA) prohibits the discharge of pollutants to U.S. waters from point sources, except pursuant to a National Pollutant Discharge Elimination System (NPDES) permit issued by the EPA or by a state under a federally authorized state program. The FWPCA authorizes the imposition of technology-based and water quality-based effluent limits to regulate the discharge of pollutants into surface waters and ground waters. The EPA has delegated authority to a number of state agencies, including those in New Jersey, New York and Connecticut, to administer the NPDES program through state action. We also have ownership interests in facilities in other jurisdictions that have their own laws and implement regulations to control discharges to their surface waters and ground waters that directly govern our facilities in those jurisdictions.

Cooling Water Intake Structure Regulation—In May 2014, the EPA issued a final cooling water intake rule under Section 316(b) of the Clean Water Act (CWA) that establishes requirements for the regulation of cooling water intakes at existing power plants and industrial facilities with a design flow of more than two million gallons of water per day.

The EPA has structured the rule so that each state Permitting Director will continue to consider renewal permits for existing power facilities on a case by case basis, based on studies related to impingement mortality and entrainment and submit the results with their permit applications to be conducted by the facilities seeking renewal permits.

Several environmental organizations and certain energy industry groups have filed suit under the CWA and the Endangered Species Act. The cases have been consolidated at the Second Circuit and a decision remains pending.

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.

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INFORMATION ABOUT OUR EXECUTIVE OFFICERS (PSEG)

Name		Age as of December 31, 2019		Office		Effective Date First Elected to Present Position
Ralph Izzo		62		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		56		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
				Vice President (VP)-Finance - PSE&G		June 2013 to October 2015
				VP-Finance - PSEG Power		December 2011 to June 2013
Ralph A. LaRossa		56		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		58		President and COO of PSEG Utilities and Clean Energy Ventures - Services; President - PSE&G		January 2020 to present
				COB - PSEG Long Island LLC		October 2017 to present
				President and COO - PSE&G		October 2017 to December 2019
				President and COO - PSEG Long Island LLC		October 2013 to October 2017
Derek M. DiRisio		55		President - Services		August 2014 to present
				VP and Controller - PSEG		January 2007 to August 2014
				VP and Controller - PSE&G		January 2007 to August 2014
				VP and Controller - PSEG Power		January 2007 to August 2014
				VP and Controller - Energy Holdings		January 2007 to August 2014
				VP and Controller - Services		January 2007 to August 2014
Tamara L. Linde		55		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
				VP-Regulatory - Services		December 2006 to July 2014
Rose M. Chernick		56		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
				VP-Finance - Energy Holdings and Corporate Planning and Analysis - Services		June 2013 to October 2015

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