PUBLIC SERVICE ENTERPRISE GROUP INC - Annual Report: 2019 (Form 10-K)

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•	fluctuations in wholesale power and natural gas markets, including the potential impacts on the economic viability of our generation units;

•	our ability to obtain adequate fuel supply;

•	market risks impacting the operation of our generating stations;

•	increases in competition in wholesale energy and capacity markets;

•	changes in technology related to energy generation, distribution and consumption and customer usage patterns;

•	economic downturns;

•	third-party credit risk relating to our sale of generation output and purchase of fuel;

•	adverse performance of our nuclear decommissioning and defined benefit plan trust fund investments and changes in funding requirements;

•	the impact of changes in state and federal legislation and regulations on our business, including PSE&G’s ability to recover costs and earn returns on authorized investments;

•	PSE&G’s proposed investment programs may not be fully approved by regulators and its capital investment may be lower than planned;

•	the impact on our New Jersey nuclear plants if such plants are not awarded Zero Emission Certificates (ZEC) in future periods, there is an adverse change in the amount of future ZEC payments, the ZEC program is overturned or modified through legal proceedings or if adverse changes are made to the capacity market construct;

•	adverse changes in energy industry laws, policies and regulations, including market structures and transmission planning;

•	the impact of state and federal actions aimed at combating climate change on our natural gas assets;

•	risks associated with our ownership and operation of nuclear facilities, including regulatory risks, such as compliance with the Atomic Energy Act and trade control, environmental and other regulations, as well as financial, environmental and health and safety risks;

•	changes in federal and state environmental regulations and enforcement;

•	delays in receipt of, or an inability to receive, necessary licenses and permits;

•	the impact of any future rate proceedings;

•	adverse outcomes of any legal, regulatory or other proceeding, settlement, investigation or claim applicable to us and/or the energy industry;

•	changes in tax laws and regulations;

•	the impact of our holding company structure on our ability to meet our corporate funding needs, service debt and pay dividends;

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•	lack of growth or slower growth in the number of customers or changes in customer demand;

•	any inability of PSEG Power to meet its commitments under forward sale obligations;

•	reliance on transmission facilities that we do not own or control and the impact on our ability to maintain adequate transmission capacity;

•	any inability to successfully develop, obtain regulatory approval for, or construct generation, transmission and distribution projects;

•	any equipment failures, accidents, severe weather events or other incidents that impact our ability to provide safe and reliable service to our customers;

•	our inability to exercise control over the operations of generation facilities in which we do not maintain a controlling interest;

•	any inability to recover the carrying amount of our long-lived assets and leveraged leases;

•	any inability to maintain sufficient liquidity;

•	any inability to realize anticipated tax benefits or retain tax credits;

•	challenges associated with recruitment and/or retention of key executives and a qualified workforce;

•	the impact of our covenants in our debt instruments on our operations; and

•	the impact of acts of terrorism, cybersecurity attacks or intrusions.

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•	Business Operations and Strategy

•	Competitive Environment

•	Employee Relations

•	Regulatory Issues

•	Environmental Matters

•	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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•	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).

•	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.

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(A)	Excludes sales from Gas rate classes that do not impact margin, specifically Contract, Non-Firm Transportation, Cogeneration Interruptible and Interruptible Services.

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•	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).

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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.

•	Generation Capacity

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

•	Generation Dispatch

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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:

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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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•	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.

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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.

•	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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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.

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•	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.

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•	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.

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

•	Energy Clearing Prices

•	Capacity Market Issues

•	Transmission Regulation

•	Compliance

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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.

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•	air pollution control,

•	climate change,

•	water pollution control,

•	hazardous substance liability, and

•	fuel and waste disposal.

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•	transportation may be unavailable if pipeline infrastructure is damaged or disabled;

•	pipeline tariff changes may adversely affect our ability to, or cost to, deliver such fuels;

•	creditworthiness of third-party suppliers, defaults by third-party suppliers on supply obligations and our ability to replace supplies currently under contract may delay or prevent timely delivery;

•	market liquidity for physical supplies of such fuels or availability of related services (e.g. storage) may be insufficient or available only at prices that are not acceptable to us;

•	variation in the quality of such fuels may adversely affect our power plant operations;

•	legislative or regulatory actions or requirements, including those related to pipeline integrity inspections, may increase the cost of such fuels;

•	fuel supplies diverted to residential heating may limit the availability of such fuels for our power plants; and

•	the loss of critical infrastructure, acts of war or terrorist attacks (including cybersecurity breaches) or catastrophic events such as fires, earthquakes, explosions, floods, severe storms or other similar occurrences could impede the delivery of such fuels.

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•	increases and decreases in generation capacity, including the addition of new supplies of power as a result of the development of new power plants, expansion of existing power plants or additional transmission capacity;

•	power transmission or fuel transportation capacity constraints or inefficiencies;

•	power supply disruptions, including power plant outages and transmission disruptions;

•	climate change and weather conditions, particularly unusually mild summers or warm winters in our market areas;

•	seasonal fluctuations;

•	economic and political conditions that could negatively impact the demand for power;

•	changes in the supply of, and demand for, energy commodities;

•	development of new fuels or new technologies for the production or storage of power;

•	federal and state regulations and actions of the ISOs; and

•	federal and state power, market and environmental regulation and legislation, including financial incentives for new renewable energy generation capacity that could lead to oversupply.

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•	prevent construction of new facilities,

•	limit or prevent continued operation of existing facilities,

•	limit or prevent the sale of energy from these facilities, or

•	result in significant additional costs,

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•	the impacts of economic downturns, including increased unemployment and less demand from C&I customers;

•	regulatory incentives to reduce energy consumption;

•	mandated energy efficiency measures;

•	DSM tools;

•	technological advances; and

•	a shift in the composition of our customer base from C&I customers to residential customers.

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•	breakdown or failure of equipment, information technology, processes or management effectiveness;

•	disruptions in the transmission of electricity;

•	labor disputes or work stoppages;

•	fuel supply interruptions;

•	transportation constraints;

•	limitations which may be imposed by environmental or other regulatory requirements; and

•	operator error, acts of war or terrorist attacks (including cybersecurity breaches) or catastrophic events such as fires, earthquakes, explosions, floods, severe storms or other similar occurrences.

•	obtain necessary governmental and regulatory approvals;

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•	obtain environmental permits and approvals;

•	obtain community support for such projects to avoid delays in the receipt of permits and approvals from regulatory authorities;

•	complete such projects within budgets and on commercially reasonable terms and conditions;

•	obtain any necessary debt financing on acceptable terms and/or necessary governmental financial incentives;

•	ensure that contracting parties, including suppliers, perform under their contracts in a timely and cost effective manner; and

•	at PSE&G, recover the related costs through rates.

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•	general economic and capital market conditions;

•	the availability of credit from banks and other financial institutions;

•	tax, regulatory and securities law developments;

•	for PSE&G, our ability to obtain necessary regulatory approvals for the incurrence of additional indebtedness;

•	investor confidence in us and our industry;

•	our current level of indebtedness and compliance with covenants in our debt agreements;

•	the success of current projects and the quality of new projects;

•	our current and future capital structure;

•	our financial performance and the continued reliable operation of our business; and

•	maintenance of our investment grade credit ratings.

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•	disruption of the operation of our assets, the fuel supply chain and the power grid,

•	theft of confidential company, employee, shareholder, vendor or customer information, which may cause us to be in breach of certain covenants and contractual obligations,

•	general business system and process interruption or compromise, including preventing us from servicing our customers, collecting revenues or the ability to record, process and/or report financial information correctly, and

•	breaches of vendors’ infrastructures where our confidential information is stored.

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(D)	Operated by Jersey Central Power & Light Company. On February 23, 2020, a Purchase Agreement was entered into to sell ownership interests in this generation facility. See Item 8. Note 4. Early Plant Retirements/Asset Dispositions for additional information.

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(A)	Amounts for 2017 and 2016 have been retrospectively adjusted to reflect guidance for Revenue from Contracts with Customers adopted on January 1, 2018. Amounts for 2015 were not required to be adjusted for this guidance and are therefore not comparative.

(B)	Income from Continuing Operations and Net Income for 2019 include an after-tax loss of $286 million related to the sale of PSEG Power’s ownership interests in the Keystone and Conemaugh fossil generation plants. See Item 8. Note 4. Early Plant Retirements/Asset Dispositions.

(C)	Income from Continuing Operations and Net Income for 2019 and 2018 include after-tax net unrealized gains (losses) on equity securities of approximately $118 million and $(125) million, respectively, in accordance with accounting guidance effective January 1, 2018.

(D)

Income from Continuing Operations and Net Income include an after-tax gain for 2018 of $39 million from the sale of PSEG Power’s Hudson and Mercer coal/gas generation plants and after-tax expenses for 2017 and 2016 of $577 million and $396 million, respectively, related to the early retirement of these plants; after-tax charges for 2019, 2018, 2017 and 2016 totaling $32 million, $5 million, $45 million and $92 million, respectively, related to investments in certain leveraged leases; and an after-tax insurance recovery for 2015 of $102 million for Superstorm Sandy. See Item 8. Note 4. Early Plant Retirements/Asset Dispositions, Note 9. Long-Term Investments and Note 10. Financing Receivables for additional information.

(E)	Income from Continuing Operations and Net Income for 2017 include the non-cash net income benefit of $745 million, primarily resulting from the remeasurement of deferred tax liabilities required due to the enactment of the Tax Act in December 2017. See Item 8. Note 22. Income Taxes for additional information for 2017.

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PSE&G—which is a public utility engaged principally in the transmission of electricity and distribution of electricity and natural gas in certain areas of New Jersey. PSE&G is subject to regulation by the New Jersey Board of Public Utilities (BPU) and the Federal Energy Regulatory Commission (FERC). PSE&G also invests in regulated solar generation projects and energy efficiency and related programs in New Jersey, which are regulated by the BPU, and

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PSEG Power—which is a multi-regional energy supply company that integrates the operations of its merchant nuclear and fossil generating assets with its power marketing businesses and fuel supply functions through competitive energy sales in well-developed energy markets primarily in the Northeast and Mid-Atlantic United States through its principal direct wholly owned subsidiaries. In addition, PSEG Power owns and operates solar generation in various states. PSEG Power’s subsidiaries are subject to regulation by FERC, the Nuclear Regulatory Commission, the Environmental Protection Agency (EPA) and the states in which they operate.

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•	utility continued its efforts to control costs while maintaining strong operational performance, including being recognized by PA Consulting as the most reliable electric utility in the Mid-Atlantic region for the 18th consecutive year, and

•	our efficient combined cycle gas units benefited our capacity factor across the natural gas fleet and were readily available to operate when needed, all while diligently adhering to our cost control programs.

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•	maintained sufficient liquidity,

•	maintained solid investment grade credit ratings, and

•	increased our annual dividend for 2019 to $1.88 per share.

•	made additional investments in T&D infrastructure projects on time and on budget,

•	continued to execute our Energy Efficiency and other existing BPU-approved utility programs, and

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•	completed construction and placed into service our BH5 generation project, the final stage of our investment program in combined cycle gas turbines.

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•	focus on controlling costs while maintaining safety, reliability and customer satisfaction and complying with applicable standards and requirements,

•	successfully manage our energy obligations and re-contract our open supply positions in response to changes in prices and demand,

•	obtain approval of and execute our utility capital investment program, including our CEF program and other investments that yield contemporaneous and reasonable risk-adjusted returns, while enhancing the resiliency of our infrastructure and maintaining the reliability of the service we provide to our customers,

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•	advocate for the continuation of the ZEC program and measures to ensure the implementation by PJM, FERC and state regulators of market design and transmission planning rules that continue to promote fair and efficient electricity markets, including recognition of the cost of emissions,

•	engage multiple stakeholders, including regulators, government officials, customers and investors, and

•	successfully operate the LIPA T&D system and manage LIPA’s fuel supply and generation dispatch obligations.

•	regulatory and political uncertainty, both with regard to future energy policy, design of energy and capacity markets, transmission policy and environmental regulation, as well as with respect to the outcome of any legal, regulatory or other proceedings,

•	the continuing impacts of the Tax Act and changes in state tax laws, and

•	the impact of reductions in demand and lower natural gas and electricity prices and increasing environmental compliance costs.

•	the acquisition, construction or disposition of T&D facilities, clean energy investments and/or generation projects, including offshore wind opportunities,

•	the disposition or reorganization of our merchant generation business or other existing businesses or the acquisition or development of new businesses,

•	the expansion of our geographic footprint, and

•	investments in capital improvements and additions, including the installation of environmental upgrades and retrofits, improvements to system resiliency, modernizing existing infrastructure and participation in transmission projects through FERC’s “open window” solicitation process.

(A)

PSEG Power’s results in 2019 include an after-tax loss of $286 million related to the sale of PSEG Power’s ownership interests in the Keystone and Conemaugh fossil generation plants. PSEG Power’s results in 2018 include an after-tax gain of $39 million from the sale of its Hudson and Mercer coal/gas generation plants and after-tax expenses of $577 million in 2017 related to the early retirement of the Hudson and Mercer generation plants. See Item 8. Note 4. Early Plant Retirements/Asset Dispositions for additional information.

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(B)	Results in 2017 include the non-cash net income benefit of $745 million, including $588 million related to PSEG Power and $147 million related to Energy Holdings, resulting from the remeasurement of deferred tax liabilities required due to the enactment of the Tax Act in December 2017.

(C)

Other includes after-tax activities at the parent company, PSEG LI and Energy Holdings as well as intercompany eliminations. Energy Holdings recorded after-tax charges totaling $32 million, $5 million and $45 million related to its investments in certain leveraged leases in 2019, 2018 and 2017, respectively. See Item 8. Note 9. Long-Term Investments and Note 10. Financing Receivables for further information.

(A)

NDT Fund Income (Expense) includes gains and losses on NDT securities which are recorded in Net Gains (Losses) on Trust Investments. See Item 8. Note 11. Trust Investments for additional information. NDT Fund Income (Expense) also includes interest and dividend income and other costs related to the NDT Fund recorded in Other Income (Deductions), interest accretion expense on PSEG Power’s nuclear Asset Retirement Obligation (ARO) recorded in Operation & Maintenance (O&M) Expense and the depreciation related to the ARO asset recorded in Depreciation and Amortization (D&A) Expense.

(B)	Net of tax (expense) benefit of $(103) million, $54 million and $(72) million for the years ended December 31, 2019, 2018 and 2017, respectively.

(C)	Net of tax (expense) benefit of $(80) million, $33 million and $68 million for the years ended December 31, 2019, 2018 and 2017, respectively.

•	higher earnings due to investments in T&D programs and the favorable impact of new rates effective November 1, 2018 as a result of the BPU’s approval of our distribution base rate proceeding at PSE&G,

•	MTM gains in 2019 as compared to MTM losses in 2018 at PSEG Power,

•	net gains in 2019 as compared to losses on equity securities in the NDT Fund at PSEG Power,

•	the favorable impact of retiree medical plan benefit changes implemented in 2019, and

•	revenue from ZECs starting in mid-April 2019 at PSEG Power,

•	largely offset by a loss related to the sale of PSEG Power’s ownership interests in the Keystone and Conemaugh generation plants in 2019.

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•	Transmission revenues increased $97 million due to higher revenue requirements calculated through our transmission formula rate, primarily to recover required investments.

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Gas distribution revenues increased $107 million due to $98 million from an increase in the distribution tariff rates effective November 1, 2018, $25 million from collection of the Gas System Modernization Program (GSMP) and GSMP II in base rates and an increase in Weather Normalization Charge (WNC) revenues of $1 million. These increases were partially offset by a $12 million decrease from lower sales volumes and $5 million in lower collections of Green Program Recovery Charges (GPRC).

•	Electric distribution revenues increased $67 million due primarily to $75 million from an increase in the distribution tariff rates effective November 1, 2018 and $16 million in higher collections of GPRC. These increases were partially offset by a $24 million decrease in sales volumes.

•	Transmission, electric distribution and gas distribution revenue requirements were $338 million lower as a result of rate reductions due to the flowback of excess deferred income tax liabilities and tax repair related accumulated deferred income taxes. This decrease is offset in Income Tax Expense.

•	Gas revenues increased $102 million due to higher BGSS prices of $83 million and higher BGSS sales volumes of $19 million.

•	Electric revenues decreased $4 million due to lower BGS sales volumes.

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•	a net increase of $374 million due to MTM gains in 2019 as compared to MTM losses in 2018. Of this amount, there was a $340 million increase from changes in forward prices in 2019 as compared to 2018, coupled with a $34 million increase due to more gains on positions reclassified to realized upon settlement, and

•	an increase of $129 million due to ZEC revenues earned since mid-April 2019,

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•	partially offset by a decrease of $112 million in electricity sold under our BGS contracts due to lower volumes and lower prices,

•	a net decrease of $63 million due primarily to lower average realized prices in the PJM, New England (NE), and New York (NY) regions coupled with lower volumes sold in the NY region, partially offset by higher volumes of electricity sold in the PJM and NE regions, and

•	a net decrease of $16 million in capacity revenues due primarily to decreases in auction prices in the PJM region, partially offset by the commencement of commercial operations of Keys and Sewaren 7 in mid-2018 and BH5 in June 2019.

•	a decrease of $107 million related to sales to third parties, primarily due to lower volumes sold and lower average sales prices,

•	partially offset by an increase of $27 million in sales under the BGSS contract, primarily due to higher average sales prices and higher volumes sold.

•	a net decrease of $90 million related to sales to third parties due primarily to lower volumes sold and lower average gas costs,

•	partially offset by a net increase of $40 million related to sales under the BGSS contract, primarily due to an increase in the average cost of gas.

•	a net decrease of $21 million due to lower MTM losses in 2019 as compared to 2018, and

•	a net decrease of $15 million due primarily to decreases in energy purchased in the NE region due to BH5 beginning commercial operations in June 2019,

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partially offset by a net increase of $13 million in higher fuel costs reflecting utilization of higher volumes of gas at Keys, Sewaren 7 and BH5, coupled with higher prices of gas in the PJM region, partially offset by utilization of lower volumes and lower prices of gas in the NY region, lower prices of gas in the NE region, utilization of lower volumes of oil in the PJM region, and lower usage of coal at lower prices in the PJM and NE regions.

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•	PSEG has a $700 million floating rate term loan maturing in November 2020,

•	PSE&G has $250 million of 3.50% Medium Term Notes (MTN) maturing in August 2020 and $9 million of 7.04% MTN maturing in November 2020, and

•	PSEG Power has $406 million of 5.13% Senior Notes maturing in April 2020.

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(A)	Moody’s ratings range from Aaa (highest) to C (lowest) for long-term securities and P1 (highest) to NP (lowest) for short-term securities.

(B)	S&P ratings range from AAA (highest) to D (lowest) for long-term securities and A1 (highest) to D (lowest) for short-term securities.

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•	Transmission—investments focused on reliability improvements and replacement of aging infrastructure.

•	Distribution—investments for new business, reliability improvements, modernization and replacement of equipment that has reached the end of its useful life.

•	Gas System Modernization—gas distribution investment program to replace aging infrastructure.

•	Energy Strong—electric and gas distribution investment program focused on electric flood mitigation and replacing aging infrastructure.

•	Clean Energy—investments associated with grid-connected solar, solar loan programs and customer energy efficiency programs.

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•	Baseline—investments to replace major parts and enhance operational performance.

•	Other—includes investments made in response to environmental, regulatory and legal mandates and other capital projects.

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•	estimated forward power and capacity prices in the years after the lease,

•	related prices of fuel for the plants,

•	dispatch rates for the plants,

•	future capital expenditures required to maintain the plants,

•	future O&M expenses,

•	discount rates, and

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•	the current estimated economic viability of the plants after the end of the base lease term.

•	estimation of dates for retirement, which can be dependent on environmental and other legislation,

•	amounts and timing of future cash expenditures associated with retirement, settlement or remediation activities,

•	discount rates,

•	cost escalation rates,

•	market risk premium,

•	inflation rates, and

•	if applicable, past experience with government regulators regarding similar obligations.

•	financial feasibility and impacts on potential early shutdown,

•	license renewals,

•	SAFSTOR alternative, which assumes the nuclear facility can be safely stored and subsequently decommissioned in a period within 60 years after operations,

•	DECON alternative, which assumes decommissioning activities begin after operations, and

•	recovery from the federal government of costs incurred for spent nuclear fuel.

•	A decrease of 1% in the discount rate would result in a $33 million increase in the Nuclear ARO.

•	An increase of 1% in the inflation rate would result in a $275 million increase in the Nuclear ARO.

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•	If we were not reimbursed by the federal government for spent fuel costs as prescribed under the Nuclear Waste Policy Act, the Nuclear ARO would increase by $379 million.

•	If we would elect or be required to decommission under a DECON alternative at Salem and Hope Creek, the Nuclear ARO would increase by $675 million.

•	If PSEG Power were to increase its early shutdown probability to 100% and retire Hope Creek and Salem starting in 2022, which is significantly earlier than the end of their current license periods, the Nuclear ARO would increase by $203 million. For additional information, see Item 8. Note 4. Early Plant Retirements/Asset Dispositions.

•	past experience regarding similar items with the BPU,

•	treatment of a similar item in an order by the BPU for another utility,

•	passage of new legislation, and

•	recent discussions with the BPU.

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•	no material impact on annual interest costs related to either the current or the long-term portion of long-term debt, and

•	a $401 million decrease in the fair value of debt, including a $14 million decrease at PSEG, a $353 million decrease at PSE&G and a $34 million decrease at PSEG Power.

•	our future contributions to these plans,

•	our financial position if our accumulated benefit obligation under our pension plans exceeds the fair value of the pension trust funds, and

•	future earnings, as we could be required to adjust pension expense and the assumed rate of return.

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•	We tested the effectiveness of controls over the evaluation of potential impairment indicators.

•	We tested the effectiveness of controls over the evaluation of legal matters related to the appeal of the initial awarding of the ZECs and the potential impact on PSEG’s evaluation of impairment indicators.

•	We tested the effectiveness of controls over the evaluation of retirement date assumptions used in the calculation of the ARO, including the probability weighting of the various cash flow scenarios.

•	We evaluated management’s judgments over the probability of early retirement of the nuclear plants and impairment triggers.

•	We evaluated management’s assumptions over the weighted-probability of early retirement of the nuclear plants used in calculating the recorded nuclear ARO balance.

•	We evaluated the related disclosures for consistency with our understanding.

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•	We tested the effectiveness of controls over the Passaic River environmental liability, including those over the evaluation of recent events and changes in circumstances that have or may give rise to a change in the allocable share of the estimated total remediation costs.

•	We tested the effectiveness of controls over the Passaic River regulatory asset, including controls over the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering the Passaic River regulatory asset in future rates.

•	With the assistance of our environmental specialists, we evaluated management’s judgments and estimates associated with the planned remediation techniques and associated estimated costs used in estimating the environmental liability.

•	We evaluated the assumptions used by management to estimate the allocable share of the environmental obligation, including consideration of publicly available information.

•	We requested and received a written response from internal counsel and external legal firms representing PSEG and evaluated the legal conclusions for consistency with those used in management’s accounting judgments and disclosures.

•	We evaluated management’s analysis over the assertion that the Passaic River regulatory asset is probable of recovery.

•	We evaluated the related disclosures for consistency with our understanding.

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•	We tested the effectiveness of controls over the calculation of the amounts refunded through the TAC, including controls over the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering the TAC regulatory assets in future rates.

•	We evaluated management’s analysis over the assertion that the TAC regulatory assets are probable of recovery.

•	We evaluated relevant regulatory orders related to the ratemaking treatment of income taxes.

•	With the assistance of our income tax specialists, we tested the accuracy of recorded income tax expense and tax related regulatory assets and liabilities.

•	We evaluated the financial statement presentation and related disclosures for consistency with our understanding.

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Public Service Electric and Gas Company (PSE&G)—which is a public utility engaged principally in the transmission of electricity and distribution of electricity and natural gas in certain areas of New Jersey. PSE&G is subject to regulation by the New Jersey Board of Public Utilities (BPU) and the Federal Energy Regulatory Commission (FERC). PSE&G also invests in regulated solar generation projects and energy efficiency and related programs in New Jersey, which are regulated by the BPU.

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PSEG Power LLC (PSEG Power)—which is a multi-regional energy supply company that integrates the operations of its merchant nuclear and fossil generating assets with its power marketing businesses and fuel supply functions through competitive energy sales in well-developed energy markets primarily in the Northeast and Mid-Atlantic United States through its principal direct wholly owned subsidiaries. In addition, PSEG Power owns and operates solar generation in various states. PSEG Power’s subsidiaries are subject to regulation by FERC, the Nuclear Regulatory Commission (NRC), the Environmental Protection Agency (EPA) and the states in which they operate.

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(A)	Includes amounts applicable to PSEG (parent company), Energy Holdings and Services.

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•	general plant assets—3 years to 20 years

•	fossil production assets—30 years to 56 years

•	nuclear generation assets—approximately 60 years

•	pumped storage facilities—76 years

•	solar assets—25 years to 35 years

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(A)	Includes primarily revenues from appliance repair services at PSE&G, solar power projects and energy management and fuel service contracts with LIPA at PSEG Power, and PSEG LI’s OSA with LIPA in Other.

(B)	Includes primarily alternative revenues at PSE&G, derivative contracts at PSEG Power, and lease contracts in Other. For the years ended December 31, 2019, 2018 and 2017, Other includes losses of $58 million, $8 million and $77 million, respectively, related to Energy Holdings’ investments in leases. For additional information, see Note 9. Long-Term Investments.

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(A)	Capacity cleared prices for BH5 through 2026 will be escalated based upon the Handy-Whitman Index. These adjustments are not included above.

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(A)	In September 2019, PSEG Power completed the sale of its ownership interests in the Keystone and Conemaugh generation plants and related assets and liabilities.

(B)	On February 23, 2020, a Purchase Agreement was entered into to sell ownership interests in this generation facility. See Note 4. Early Plant Retirements/Asset Dispositions for additional information.

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•	Asset Retirement Obligation: These costs represent the differences between rate-regulated cost of removal accounting and asset retirement accounting under GAAP. These costs will be recovered in future rates as assets are retired.

•	BRC: Represents deferred costs, primarily comprised of storm costs incurred in the cleanup of major storms from 2010 through 2018, which are being amortized over five years pursuant to the 2018 Distribution Base Rate Case Settlement.

•

Deferred Income Tax Regulatory Assets: These amounts relate to deferred income taxes arising from utility operations that have not been included in customer rates relating to depreciation, investment tax credits and other flow-through items, including the flowback to customers of accumulated deferred income taxes related to tax repair deductions. As part of its base rate case settlement with the BPU and the establishment of the TAC mechanism in 2018, PSE&G agreed to a ten-year flowback to customers of its accumulated deferred income taxes from previously realized tax repair deductions which resulted in the recognition of a $581 million Regulatory Asset and Regulatory Liability as of September 30, 2018. In addition, PSE&G agreed to the current flowback of tax benefits from ongoing tax repair deductions as realized which results in the recording of a Regulatory Asset upon flowback. For the years ended December 31, 2019 and 2018, PSE&G had provided $58 million and $15 million, respectively, in current tax repair flowbacks to customers. The recovery and amortization of the tax repair-related Deferred Income Tax Regulatory Assets will be determined in PSE&G’s subsequent base rate cases.

•

Deferred Income Tax Regulatory Liabilities: These liabilities relate to amounts due to customers for excess deferred income taxes as a result of the reduction in the federal income tax provided in the Tax Cuts and Jobs Act of 2017 (the Tax Act), and accumulated deferred income taxes from previously realized tax repair deductions as described above. As part of its settlement with its regulators, PSE&G agreed to refund the excess deferred income taxes as follows:

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$705 million of distribution-related excess deferred income taxes refunded to customers over five years through PSE&G’s TAC mechanism with the remaining $1.1 billion of distribution-related excess deferred income taxes refunded to customers over the remaining useful life of distribution property, plant and equipment. As of December 31, 2019 and 2018, the balance remaining to be flowed back to customers was $1.6 billion and $1.8 billion, respectively.

•	$150 million of transmission-related excess deferred income taxes refunded to customers during the year ended December 31, 2019 with the remaining $977 million of transmission-related excess deferred income taxes returned over the remaining useful life of the property, plant and equipment.

•	Electric and Gas Cost of Removal: PSE&G accrues and collects in rates for the cost of removing, dismantling and disposing of its T&D assets upon retirement. The Regulatory Asset or Liability for non-legally required cost of removal represents the difference between amounts collected in rates and costs actually incurred.

•

Electric Energy Costs—BGS: These costs represent the over or under recovered amounts associated with BGS, as approved by the BPU. Pursuant to BPU requirements, PSE&G serves as the supplier of last resort for electric customers within its service territory that are not served by another supplier. Pricing for those services are set by the BPU as a pass-through, resulting in no margin for PSE&G’s operations. Over or under recovered balances with interest are returned or recovered through monthly filings.

•

Gas Costs—BGSS: These costs represent the over or under recovered amounts associated with BGSS, as approved by the BPU. Pursuant to BPU requirements, PSE&G serves as the supplier of last resort for gas customers within its service territory that are not served by another supplier. Pricing for those services are set by the BPU as a pass-through, resulting in no margin for PSE&G’s operations. Over or under collected balances are returned or recovered through an annual filing. Interest is accrued only on over recovered balances.

•

Gas Margin Adjustment Clause: This mechanism credits Firm delivery customers for net distribution margin revenue collected from Transportation Gas Service Non-Firm (TSG-NF) delivery customers. The balance represents the difference between the net margin collected from the TSG-NF customers versus bill credits provided to Firm delivery customers. Over or under recovered balances with interest are returned or recovered through the subsequent annual filing.

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GPRC: This amount represents costs of the over or under collected balances associated with various renewable energy and energy efficiency programs. PSE&G files annually with the BPU for recovery of amounts that include a return on and of its investment over the lives of the underlying investments and capital assets which range from five to ten years. Interest is accrued monthly on any over or under recovered balances. Components of the GPRC include: Carbon Abatement, Energy Efficiency Economic Stimulus Program (EEE), EEE Extension Program, EEE Extension II Program, the Demand Response Program, Solar Generation Investment Program (Solar 4 All®), Solar 4 All® Extension, Solar 4 All® Extension II, Solar Loan II Program, Solar Loan III Program and the Energy Efficiency (EE) 2017 Program.

•	MGP Remediation Costs: Represents the low end of the range for the remaining environmental investigation and remediation program cleanup costs for MGPs that are probable of recovery in future rates. Once these costs are incurred, they are recovered through the RAC in the SBC over a seven year period with interest.

•	New Jersey Clean Energy Program: The BPU approved future funding requirements for Energy Efficiency and Renewable Energy Programs through the first half of 2020. The BPU funding requirements are recovered through the SBC.

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Pension and OPEB Costs: Pursuant to the adoption of accounting guidance for employers’ defined benefit pension and OPEB plans, PSE&G recorded the unrecognized costs for defined benefit pension and other OPEB plans on the balance sheet as a Regulatory Asset. These costs represent actuarial gains or losses and prior service costs which have not been expensed. These costs are amortized and recovered in future rates.

•	RAC (Other SBC): Costs incurred to clean up MGPs which are recovered over seven years with interest through an annual filing.

•

SBC: The SBC, as authorized by the BPU and the New Jersey Electric Discount and Energy Competition Act, includes costs related to PSE&G’s electric and gas business as follows: (1) the Universal Service Fund; (2) Energy Efficiency and Renewable Energy Programs; (3) Electric bad debt expense; and (4) the RAC for incurred MGP remediation expenditures. Over or under recovered balances with interest are to be returned or recovered through an annual filing.

•

TAC: This represents the over or under collected balances associated with the return of excess accumulated deferred income taxes and the flowback of previously realized and current tax repair deductions under a mechanism approved by the BPU in PSE&G’s 2018 Base Rate Case Settlement. Over or under collected balances are returned or recovered through an annual filing. PSE&G includes a return component on the flowback of the excess accumulated deferred income taxes and the previously realized tax repairs. Interest is accrued monthly on any over or under recovered balances.

•	Unamortized Loss on Reacquired Debt and Debt Expense: Represents losses on reacquired long-term debt and expenses associated with issuances of new debt, which are recovered through rates over the remaining life of the debt.

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WNC: This represents the over or under recovery of gas margin which is filed annually with the BPU. The WNC requires PSE&G to calculate, at the end of each October-to-May period, the level by which margin revenues differed from what would have resulted if normal weather had occurred. Over recoveries are returned to customers in the next winter season while under recoveries (subject to an earnings cap) are recovered from customers in the next winter season.

•

Electric and Gas Distribution Base Rate Filings—In October 2018, the BPU issued an Order approving the settlement of PSE&G’s distribution base rate proceeding with new rates effective November 1, 2018. The settlement resulted in a net reduction in overall annual revenues of approximately $13 million, comprised of a $212 million increase in base revenues, including recovery of deferred storm costs, offset by the return of tax benefits of approximately $225 million. The tax benefits include the flowback to customers of excess accumulated deferred income taxes resulting from the reduction of the federal income tax rates provided in the Tax Act as well as the accumulated deferred income taxes from previously realized tax repair deductions and tax benefits from future tax repair deductions as realized. The Order provided for a $9.5 billion rate base, a 9.6% return on equity for PSE&G’s distribution business and a 54% equity component of its capitalization structure. In addition to the $13 million annual revenue reduction, the Order provided for a $28 million one-time refund to customers in November and December 2018 for taxes collected at the higher federal income tax rate for the January 1 to March 31, 2018 period. Previously,

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•	Transmission Formula Rate Filings—In October 2019, PSE&G filed its 2020 Transmission Formula Rate Annual Update with FERC requesting approximately $332 million in increased annual transmission revenue effective January 1, 2020, subject to true-up.

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BGSS—In September 2019, the BPU provisionally approved PSE&G’s request to decrease its BGSS rates from approximately 35 cents to 34 cents per therm for residential gas customers effective October 1, 2019. In December 2019, a self-implementing reduction of 2 cents per therm was filed with the BPU to further reduce the BGSS rate to approximately 32 cents per therm effective January 1, 2020, which was given final approval by the BPU in February 2020. The final reduction in the BGSS rate to 32 cents per therm will decrease annual BGSS revenues by approximately $34 million. In addition, PSE&G issued a self-implementing one-time bill credit of 7.5 cents per therm to be returned during the months of February and March 2020.

•	Gas System Modernization Program II (GSMP II)—In November 2019, the BPU approved PSE&G’s first GSMP II cost recovery petition requesting approximately $17 million in gas revenues on an annual basis, which included GSMP II investments in service as of August 31, 2019. The increase was effective December 1, 2019.

•	Gas System Modernization Program I (GSMP I)—In September 2019, the BPU approved PSE&G’s final GSMP I cost recovery petition requesting approximately $11 million in gas revenues, on an annual basis, which included GSMP I investments in service as of June 30, 2019. The increase was effective October 1, 2019.

•

GPRC—In February 2020, the BPU approved a six-month extension of PSE&G’s Energy Efficiency (EE) 2017 component of its GPRC programs, authorizing $111 million of EE investments and $19 million of administrative costs for recovery over the course of the programs though its existing filing mechanism. In September 2019, the BPU approved a one year extension of PSE&G’s EE 2017 component of its GPRC programs, authorizing an additional $27 million of EE investments and $6 million of additional administrative costs for recovery though its existing filing mechanism.

•	RAC—In January 2020, PSE&G filed its RAC 27 petition with the BPU seeking recovery of $53 million of net MGP remediation expenditures from August 1, 2018 through July 31, 2019. This matter is pending.

•	SBC—In January 2020, the BPU approved PSE&G’s petition to increase electric and gas rates by approximately $27 million and $7 million, respectively, on an annual basis, in order to recover electric and gas costs incurred through October 31, 2019 under its EE and Renewable Energy and Social Programs. The new rates were effective February 1, 2020.

•

TAC—In January 2020, the BPU approved PSE&G’s initial TAC filing on a provisional basis allowing a reduction to electric and gas revenues by $15 million and $10 million, respectively, on an annual basis effective February 1, 2020. The TAC was a result of the settlement of PSE&G’s distribution base rate case in 2018. The TAC allows for the flowback to customers of excess accumulated deferred income taxes resulting from the reduction of the federal income

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•	WNC—In February 2020, the BPU gave final approval to PSE&G’s 2019-2020 WNC rates allowing an approximate $8 million of overcollections from the colder-than-normal 2018-2019 Winter Period, to be refunded to customers over the 2019-2020 Winter Period, with rates effective October 1, 2019.

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ZEC Program—In April 2019, the BPU authorized the New Jersey EDCs, including PSE&G, to purchase ZECs from eligible nuclear plants selected by the BPU. In conjunction with this Order, the BPU authorized tariffs to collect a non-bypassable distribution charge in the amount of $0.004 per KWh from each EDC’s retail distribution customers to be used to purchase ZECs from the selected plants. Each EDC purchases ZECs on a monthly basis with payment to be made annually following completion of each energy year. Under the program, any revenue collected in excess of the purchase price will be refunded to customers in the following year.

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(A)	During the three years ended December 31, 2019, 2018 and 2017, dividends from these investments were $15 million, $16 million and $18 million, respectively.

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(A)	In September 2019, PSEG Power completed the sale of its ownership interests in the Keystone and Conemaugh generation plants and related assets and liabilities.

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(A)	REMA emerged from Chapter 11 of the U.S. Bankruptcy Code in December 2018. For additional information, see Note 9. Long-Term Investments.

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(A)	Equity Securities—Investments in marketable equity securities within the NDT Fund are primarily in common stocks within a broad range of industries and sectors. Unrealized gains and losses on these securities are recorded in Net Income.

(B)

Debt Securities (Government)—Unrealized gains and losses on these securities are recorded in Accumulated Other Comprehensive Income (Loss). The unrealized losses on PSEG Power’s NDT investments in U.S. Treasury obligations and Federal Agency mortgage-backed securities were caused by interest rate changes. These investments are guaranteed by the U.S. government or an agency of the U.S. government. PSEG Power also has investments in municipal bonds that are primarily in investment grade securities. It is not expected that these securities will settle for less than their amortized cost. Since PSEG Power does not intend to sell these securities nor will it be more-likely-than-not required to sell, PSEG Power does not consider these debt securities to be other-than-temporarily impaired as of December 31, 2019.

(C)

Debt Securities (Corporate)—Unrealized gains and losses on these securities are recorded in Accumulated Other Comprehensive Income (Loss). PSEG Power’s investments in corporate bonds are primarily in investment grade securities. It is not expected that these securities would settle for less than their amortized cost. Since PSEG Power does not intend to sell these securities nor will it be more-likely-than-not required to sell, PSEG Power does not consider these debt securities to be other-than-temporarily impaired as of December 31, 2019.

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(A)	Includes activity in accounts related to the liquidation of funds being transitioned to new managers.

(B)	The cost of these securities was determined on the basis of specific identification.

(C)	Effective January 1, 2018, unrealized gains (losses) on equity securities are recorded in Net Income instead of Other Comprehensive Income (Loss).

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(A)

Debt Securities (Government)—Unrealized gains and losses on these securities are recorded in Accumulated Other Comprehensive Income (Loss). The unrealized losses on PSEG’s Rabbi Trust investments in U.S. Treasury obligations and Federal Agency mortgage-backed securities were caused by interest rate changes. These investments are guaranteed by the U.S. government or an agency of the U.S. government. PSEG also has investments in municipal bonds that are primarily in investment grade securities. It is not expected that these securities will settle for less than their amortized cost. Since PSEG does not intend to sell these securities nor will it be more-likely-than-not required to sell, PSEG does not consider these debt securities to be other-than-temporarily impaired as of December 31, 2019.

(B)

Debt Securities (Corporate)—Unrealized gains and losses on these securities are recorded in Accumulated Other Comprehensive Income (Loss). PSEG’s investments in corporate bonds are primarily in investment grade securities. It is not expected that these securities would settle for less than their amortized cost. Since PSEG does not intend to sell these securities nor will it be more-likely-than-not required to sell, PSEG does not consider these debt securities to be other-than-temporarily impaired as of December 31, 2019.

(A)	Includes activity in accounts related to the liquidation of funds being transitioned to new managers.

(B)	The cost of these securities was determined on the basis of specific identification.

(C)	Effective January 1, 2018, unrealized gains (losses) on equity securities are recorded in Net Income instead of Other Comprehensive Income (Loss).

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(A)	Not reflected as expense in Consolidated Statements of Operations

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(A)	Represents projected benefit obligation for pension benefits and the accumulated postretirement benefit obligation for other benefits. The vested benefit obligation is the actuarial present value of the vested benefits to which the employee is currently entitled but based on the employee’s expected date of separation or retirement.

(B)

Includes $695 million ($499 million, after-tax) and $619 million ($360 million, after-tax) in Accumulated Other Comprehensive Loss related to Pension and OPEB as of December 31, 2019 and 2018, respectively. Also includes Regulatory Assets of $1,284 million and Deferred Assets of $137 million as of December 31, 2019 and Regulatory Assets of $1,090 million and Deferred Assets of $127 million as of December 31, 2018.

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(A)	The Collective Investment Fund publishes a daily net asset value (NAV) which participants may use for daily redemptions without restrictions (Level 1). Certain temporary investments are valued using inputs such as time-to-maturity, coupon rate, quality rating and current yield (Level 2).

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(B)	Common stocks and preferred stocks are measured using observable data in active markets and considered Level 1.

(C)	Commingled Funds that allow daily redemption at their daily published NAV without restrictions are classified as Level 1. Commingled Funds that publish daily NAV but with certain near-term redemption restrictions which prevent redemption at the published daily NAV are classified as Level 2.

(D)	Investment in a publicly traded limited partnership.

(E)

Debt securities include mainly investment grade corporate and municipal bonds, U.S. Treasury obligations and Federal Agency asset-backed securities with a wide range of maturities. These investments are valued using an evaluated pricing approach that varies by asset class and reflects observable market information such as the most recent exchange price or quoted bid for similar securities. Market-based standard inputs typically include benchmark yields, reported trades, broker/dealer quotes and issuer spreads or the most recent quotes for similar securities which are a Level 2 measure.

(F)

Certain commingled equity funds are not included in the fair value hierarchy as they are measured at fair value using the NAV per share (or its equivalent) practical expedient. These funds do not meet the definition of readily determinable fair value due to the frequency of publishing NAV (monthly). The objectives of these funds are mainly tracking the S&P Index or achieving long-term growth through investment in foreign equity securities and the Morgan Stanley Capital International Index.

(G)

The unlisted real estate fund invests in office, apartment, industrial and retail space. The fund is valued using the NAV per unit of funds. The investment value of the real estate properties are determined on a quarterly basis by independent market appraisers engaged by the board of directors of the fund. The ability to redeem funds is subject to the availability of cash arising from net investment income, allocations and the sale of investments in the normal course of business. The fund’s NAV is published quarterly. In addition, redemptions require one quarter advance notice prior to redemption and are fulfilled quarterly. The fund, therefore, does not meet the definition of readily determinable fair value. The purpose of the fund is to acquire, own, hold for investment and ultimately dispose of investments in real estate and real estate-related assets with the intention of achieving current income, capital appreciation or both.

(H)

Private equity investments primarily include various limited partnerships that invest in either operating companies through acquisitions or developing a portfolio of non-U.S. distressed investments to maximize total return on capital. These investments are valued at NAV (or its equivalent) on a quarterly basis and have significant redemption restrictions preventing redemption until fund liquidation and limited ability to sell these investments. Fund liquidation is not expected to occur for several more years. These investments are not included in the fair value hierarchy in accordance with the guidance on NAV practical expedient.

(I)	Excludes net receivables of $15 million and $14 million as of December 31, 2019 and 2018, respectively, which consist of interest, dividends and receivables and payables related to pending securities sales and purchases. In addition, the table excludes cash and foreign currency of $5 million as of December 31, 2019.

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(A)	Represents projected benefit obligation for pension benefits and the accumulated postretirement benefit obligation for other benefits. The vested benefit obligation is the actuarial present value of the vested benefits to which the employee is currently entitled but based on the employee’s expected date of separation or retirement.

(B)	Amounts equal to the accrued pension and OPEB costs of Servco are offset in Long-Term Receivable of VIE on PSEG’s Consolidated Balance Sheets.

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(A)	Investments in commingled equity and bond funds have a readily determinable fair value as they publish a daily NAV available to investors which is the basis for current transactions and contain certain redemption restrictions requiring advance notice of one to two days for withdrawals (Level 2).

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•	support current exposure, interest and other costs on sums due and payable in the ordinary course of business, and

•	obtain credit.

•	counterparty collateral calls related to commodity contracts of its subsidiaries, and

•	certain creditworthiness standards as guarantor under performance guarantees of its subsidiaries.

•	its subsidiaries would have to fully utilize the credit granted to them by every counterparty to whom PSEG Power has provided a guarantee, and

•	the net position of the related contracts would have to be “out-of-the-money” (if the contracts are terminated, PSEG Power would owe money to the counterparties).

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(A)	Prices set in the 2020 BGS auction will become effective on June 1, 2020 when the 2017 BGS auction agreements expire.

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(A)	Secured by essentially all property of PSE&G pursuant to its First and Refunding Mortgage.

(B)	The Pennsylvania Economic Development Financing Authority (PEDFA) bond that is serviced and secured by PSEG Power Pollution Control Notes is a variable rate bond that is in weekly reset mode.

•	issued $750 million of 2.875% Senior Notes due June 2024,

•	repaid a $350 million term loan with an interest rate of 1 month LIBOR + 0.80%, and

•	retired $400 million of 1.60% Senior Notes at maturity.

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•	issued $375 million of 3.20% Secured Medium-Term Notes, Series M, due May 2029,

•	issued $375 million of 3.85% Secured Medium-Term Notes, Series M, due May 2049,

•	retired $250 million of 1.80% Medium-Term Notes, Series I, at maturity, and

•	retired $250 million of 2.00% Medium-Term Notes, Series J, at maturity.

•	PSEG Power executed an extension of the letter of credit backing $44 million of PEDFA Variable Rate Demand Bonds. The existing letter of credit, which was scheduled to expire in November 2019, was extended through March 2022.

(B)	PSE&G facility will be reduced by $4 million in March 2022.

(C)	PSEG Power facilities will be reduced by $12 million in March 2022.

(D)	The primary use of PSEG’s and PSE&G’s credit facilities is to support their respective Commercial Paper Programs, under which as of December 31, 2019, PSEG had $753 million outstanding at a weighted average interest rate of 2.08%. PSE&G had $362 million outstanding at a weighted average interest rate of 1.95% under its Commercial Paper Program as of December 31, 2019.

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(A)	As of December 31, 2019 and 2018, fair value includes floating rate term loans of $700 million and $1,050 million, respectively. The fair values of the term loan debt (Level 2 measurement) approximate the carrying value because the interest payments are based on LIBOR rates that are reset monthly and the debt is redeemable at face value by PSEG at any time.

(B)

Given that these bonds do not trade actively, the fair value amounts of taxable debt securities (primarily Level 2 measurements) are generally determined by a valuation model that is based on a conventional discounted cash flow methodology and utilizes assumptions of current market pricing curves. In order to incorporate the credit risk into the discount rates, pricing (i.e. U.S. Treasury rate plus credit spread) is based on expected new issue pricing across each of the companies’ respective debt maturity spectrum. The credit spreads of various tenors obtained from this information are added to the appropriate benchmark U.S. Treasury rates in order to determine the current market yields for the various tenors. The yields are then converted into discount rates of various tenors that are used for discounting the respective cash flows of the same tenor for each bond or note. The fair value amounts above do not represent the price at which the outstanding debt may be called for redemption by each issuer under their respective debt agreements.

(A)	PSEG did not issue any new shares under the Dividend Reinvestment and Stock Purchase Plan or the Employee Stock Purchase Plan in 2019 or 2018.

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(A)	Substantially all of PSEG Power’s and PSEG’s derivative instruments are contracts subject to master netting agreements. Contracts not subject to master netting or similar agreements are immaterial and did not have any collateral posted or received as of December 31, 2019 and 2018.

(B)

Represents the netting of fair value balances with the same counterparty (where the right of offset exists) and the application of cash collateral. All cash collateral (received) posted that has been allocated to derivative positions, where the right of offset exists, has been offset on the Consolidated Balance Sheets. As of December 31, 2019 and 2018, PSEG Power had net cash collateral payments to counterparties of $44 million and $393 million, respectively. Of these net cash collateral (receipts) payments, $(2) million as of December 31, 2019 and $153 million as of December 31, 2018 were netted against the corresponding net derivative contract positions. Of the $(2) million as of December 31, 2019, $(1) million was netted against current assets, and $(1) million was netted against noncurrent assets. Of the $153 million as of December 31, 2018, $(2) million was netted against current assets, $(3) million was netted against noncurrent assets, $96 million was netted against current liabilities and $62 million was netted against noncurrent liabilities.

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(A)	Represents net exposure of $213 million with PSE&G and $50 million with a non-affiliated counterparty.

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(A)	Represents money market mutual funds.

(B)	Level 1—These contracts represent natural gas futures contracts executed on NYMEX, and are being valued solely

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(C)

As of December 31, 2019, the fair value measurement table excludes foreign currency of $2 million in the NDT Fund. The NDT Fund maintains investments in various equity and fixed income securities. The Rabbi Trust maintains investments in a Russell 3000 index fund and various fixed income securities. These securities are generally valued with prices that are either exchange provided (equity securities) or market transactions for comparable securities and/or broker quotes (fixed income securities).

(D)	Interest rate swaps are valued using quoted prices on commonly quoted intervals, which are interpolated for periods different than the quoted intervals, as inputs to a market valuation model. Market inputs can generally be verified and model selection does not involve significant management judgment.

(E)	Represents the netting of fair value balances with the same counterparty (where the right of offset exists) and the application of collateral. See Note 18. Financial Risk Management Activities for additional detail.

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(B)	Includes $(7) million in settlements for derivative contracts in 2019.

(C)	There were no transfers in 2019 and 2018 to or from Level 3.

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(A)	Other consists of activity at PSEG (as parent company), Energy Holdings, Services, PSEG LI and intercompany eliminations.

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(A)	Includes amounts applicable to Energy Holdings and PSEG LI, which are below the quantitative threshold for separate disclosure as reportable segments. Other also includes amounts applicable to PSEG (parent corporation) and Services.

(B)	Intercompany eliminations primarily relate to intercompany transactions between PSE&G and PSEG Power. For a further discussion of the intercompany transactions between PSE&G and PSEG Power, see Note 26. Related-Party Transactions.

(C)	Includes an after-tax loss of $286 million related to the sale of PSEG Power’s ownership interests in the Keystone and Conemaugh generation plants. See Note 4. Early Plant Retirements/Asset Dispositions for additional information.

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(A)

PSE&G has entered into a requirements contract with PSEG Power under which PSEG Power provides the gas supply services needed to meet PSE&G’s BGSS and other contractual requirements. PSEG Power has also entered into contracts to supply energy, capacity and ancillary services to PSE&G through the BGS auction process and sells ZECs to PSE&G under the ZEC program. The rates in the BGS and BGSS contracts and for the ZEC sales are prescribed by the BPU. BGS and BGSS sales are billed and settled on a monthly basis. ZEC sales are billed on a monthly basis and settled annually following completion of each energy year. In addition, PSEG Power and PSE&G provide certain technical services for each other generally at cost in compliance with FERC and BPU affiliate rules.

(B)	Services provides and bills administrative services to PSE&G and PSEG Power at cost. In addition, PSE&G and PSEG Power have other payables to Services, including amounts related to certain common costs, which Services pays on behalf of each of the operating companies.

(C)

PSEG files a consolidated federal income tax return with its affiliated companies. A tax allocation agreement exists between PSEG and each of its affiliated companies. The general operation of these agreements is that the subsidiary company will compute its taxable income on a stand-alone basis. If the result is a net tax liability, such amount shall be paid to PSEG. If there are net operating losses and/or tax credits, the subsidiary shall receive payment for the tax savings from PSEG to the extent that PSEG is able to utilize those benefits.

(D)	PSE&G and PSEG Power have advanced working capital to Services. The amounts are included in Other Noncurrent Assets on PSE&G’s and PSEG Power’s Consolidated Balance Sheets.

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(E)	PSEG Power’s short-term loans with PSEG are for working capital and other short-term needs. Interest Income and Interest Expense relating to these short-term funding activities were immaterial.

(A)	The decrease in Operating Income and Net Income at PSEG consolidated and PSEG Power in the second quarter of 2019 as compared to the same quarter in 2018 was primarily due to the loss in 2019 related to the sale of PSEG Power’s ownership interests in the Keystone and Conemaugh fossil generation plants, offsetting MTM net gains in 2019 as compared to net losses in 2018.

(B)	The increase in Net Income at PSEG consolidated and PSEG Power in the fourth quarter of 2019 as compared to the same quarter in 2018 was primarily due to net gains in 2019 as compared to net losses in 2018 on equity securities in PSEG Power’s NDT Fund.

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•	Any amendment (other than one that is technical, administrative or non-substantive) that we adopt to our Standards; and

•	Any grant by us of a waiver from the Standards that applies to any director or executive officer and that relates to any element enumerated by the SEC.

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a.	Public Service Enterprise Group Incorporated’s Consolidated Balance Sheets as of December 31, 2019 and 2018 and the related Consolidated Statements of Operations, Comprehensive Income, Cash Flows and Stockholders’ Equity for the three years ended December 31, 2019 on pages 73 through 78.

b.	Public Service Electric and Gas Company’s Consolidated Balance Sheets as of December 31, 2019 and 2018 and the related Consolidated Statements of Operations, Comprehensive Income, Cash Flows and Common Stockholder’s Equity for the three years ended December 31, 2019 on pages 79 through 84.

c.	PSEG Power LLC’s Consolidated Balance Sheets as of December 31, 2019 and 2018 and the related Consolidated Statements of Operations, Comprehensive Income, Cash Flows and Capitalization and Member’s Equity for the three years ended December 31, 2019 on pages 85 through 90.

a.	PSEG’s Financial Statement Schedules:

b.	PSE&G’s Financial Statement Schedules:

c.	PSEG Power’s Financial Statement Schedules:

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(1)	Filed as Exhibit 3.1a with Quarterly Report on Form 10-Q for the quarter ended March 31, 2007, File No. 001-09120, on May 4, 2007 and incorporated herein by this reference.

(2)	Filed as Exhibit 3.1b with Quarterly Report on Form 10-Q for the quarter ended March 31, 2007, File No. 001-09120, on May 4, 2007 and incorporated herein by this reference.

(3)	Filed as Exhibit 3.1c with Quarterly Report on Form 10-Q for the quarter ended March 31, 2007, File No. 001-09120, on May 4, 2007 and incorporated herein by this reference.

(4)	Filed as Exhibit 99.1 with Current Report on Form 8-K, File No. 001-09120, on December 16, 2015 and incorporated herein by this reference.

(5)	Filed as Exhibit 4(f) with Quarterly Report on Form 10-Q for the quarter ended March 31, 1998, File No. 001-09120, on May 13, 1998 and incorporated herein by this reference.

(6)	Filed as Exhibit 4(f) with Annual Report on Form 10-K for the year ended December 31, 1998, File No. 001-09120, on February 23, 1999 and incorporated herein by this reference

(7)	Filed as Exhibit 10.1 with Quarterly Report on Form 10-Q for the quarter ended September 30, 2019, File No. 001-09120, on October 31, 2019 and incorporated herein by this reference.

(8)	Filed as Exhibit 10.2 with Quarterly Report on Form 10-Q for the quarter ended September 30, 2019, File No. 001-09120, on October 31, 2019 and incorporated herein by this reference.

(9)	Filed as Exhibit 10a(3) with Annual Report on Form 10-K for the year ended December 31, 2018, File No. 001-09120 on February 27, 2019 and incorporated herein by this reference.

(10)	Filed as Exhibit 10a(4) with Annual Report on Form 10-K for the year ended December 31, 2018, File No. 001-09120 on February 27, 2019 and incorporated herein by this reference.

(11)	Filed as Exhibit 10a(5) with Annual Report on Form 10-K for the year ended December 31, 2018, File No. 001-09120 on February 27, 2019 and incorporated herein by this reference.

(12)	Filed as Exhibit 10 with Quarterly Report on Form 10-Q for the quarter ended September 30, 2002, File No. 001-09120, on November 4, 2002 and incorporated herein by this reference.

(13)	Filed as Exhibit 10a(7) with Annual Report on Form 10-K for the year ended December 31, 2000, File No. 001-09120, on March 6, 2001 and incorporated herein by this reference.

(14)	Filed as Exhibit 10a(11) with Annual Report on Form 10-K for the year ended December 31, 2008, File No. 001-09120, on February 26, 2009 and incorporated herein by this reference.

(15)	Filed as Exhibit 10.3 with Quarterly Report on Form 10-Q for the quarter ended September 30, 2019, File No. 001-09120 on October 31, 2019 and incorporated herein by this reference.

(16)	Filed as Exhibit 99 with Current Report on Form 8-K, File Nos. 001-09120, 000-49614 and 001-00973, on December 22, 2008 and incorporated herein by this reference.

(17)	Filed as Exhibit 10a(17) with Annual Report on Form 10-K for the year ended December 31, 2002, File No. 001-09120, on February 26, 2003 and incorporated herein by this reference.

(18)	Filed as Exhibit 10a(20) with Annual Report on Form 10-K for the year ended December 31, 2002, File No. 001-09120, on February 26, 2003 and incorporated herein by this reference.

(19)	Filed as Exhibit 10 with Quarterly Report on Form 10-Q for the quarter ended March 31, 2013, File No. 001-09120, on May 1, 2013 and incorporated herein by this reference.

(20)	Filed as Exhibit 10.1 with Current Report on Form 8-K, File No. 001-09120, on February 19, 2009 and incorporated herein by this reference.

(21)	Filed as Exhibit 10a(15) with Annual Report on Form 10-K for the year ended December 31, 2018, File No. 001-09120 on February 27, 2019 and incorporated herein by this reference.

(22)	Filed as Exhibit 10a with Annual Report on Form 10-K for the year ended December 31, 2014, File No. 001-09120, on February 26, 2015, and incorporated herein by this reference.

(23)	Filed as Exhibit 10 with Quarterly Report on Form 10-Q for the quarter ended September 30, 2015, File No. 001-09120, on October 30, 2015, and incorporated herein by this reference.

(24)	Filed as Exhibit 10a(20) with Annual Report on Form 10-K for the year ended December 31, 2017, File No. 001-09120 on February 26, 2018 and incorporated herein by this reference.

(25)	Filed as Exhibit 3a(1) on Form 8-A, File No. 001-00973, on February 4, 1994 and incorporated herein by this reference.

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(26)	Filed as Exhibit 3a(2) on Form 8-A, File No. 001-00973, on February 4, 1994 and incorporated herein by this reference.

(27)	Filed as Exhibit 3a(3) on Form 8-A, File No. 001-00973, on February 4, 1994 and incorporated herein by this reference.

(28)	Filed as Exhibit 3a(4) on Form 8-A, File No. 001-00973, on February 4, 1994 and incorporated herein by this reference.

(29)	Filed as Exhibit 3a(5) on Form 8-A, File No. 001-00973, on February 4, 1994 and incorporated herein by this reference.

(30)	Filed as Exhibit 3.3 with Quarterly Report on Form 10-Q for the quarter ended March 31, 2007, File No. 001-00973, on May 4, 2007 and incorporated herein by this reference.

(31)	Filed as Exhibit 4b(1) with Annual Report on Form 10-K for the year ended December 31, 1980, File No. 001-00973, on February 18, 1981 and incorporated herein by this reference.

(32)	Filed as Exhibit 4b(3) with Annual Report on Form 10-K for the year ended December 31, 1980, File No. 001-00973, on February 18, 1981 and incorporated herein by this reference.

(33)	Filed as Exhibit 4b(4) with Annual Report on Form 10-K for the year ended December 31, 1980, File No. 001-00973, on February 18, 1981 and incorporated herein by this reference.

(34)	Filed as Exhibit 4(i) on Form 8-A, File No. 001-00973, on June 1, 1991 and incorporated herein by this reference.

(35)	Filed as Exhibit 4(ii) on Form 8-A, File No. 001-00973, on May 25, 1993 and incorporated herein by this reference.

(36)	Filed as Exhibit 4a(28) with Annual Report on Form 10-K for the year ended December 31, 2004, File No. 001-00973, on March 1, 2005 and incorporated herein by this reference.

(37)	Filed as Exhibit 4a(28) with Annual Report on Form 10-K for the year ended December 31, 2007, File No. 001-00973, on February 28, 2008 and incorporated herein by this reference.

(38)	Filed as Exhibit 4a(30) with Annual Report on Form 10-K for the year ended December 31, 2009, File No. 001-00973, on February 25, 2010 and incorporated herein by this reference.

(39)	Filed as Exhibit 4a(32) with Annual Report on Form 10-K for the year ended December 31, 2012, File No. 001-00973, on February 26, 2013, and incorporated herein by this reference.

(40)	Filed as Exhibit 4 with Quarterly Report on Form 10-Q for the quarter ended June 30, 2013, File No. 001-00973, on July 30, 2013, and incorporated herein by this reference.

(41)	Filed as Exhibit 4a(22) with Quarterly Report on Form 10-Q for the quarter ended September 30, 2014, File No. 001-09120, on October 30, 2014 and incorporated herein by this reference.

(42)	Filed as Exhibit 4a(23) with Quarterly Report on Form 10-Q for the quarter ended June 30, 2015, File No. 001-09120, on July 31, 2015 and incorporated herein by this reference.

(43)	Filed as Exhibit 4a(14) with Annual Report on Form 10-K for the year ended December 31, 2016, File No. 001-00973, on February 27, 2017 and incorporated herein by this reference.

(44)	Filed as Exhibit 4a(15) with Quarterly Report on Form 10-Q for the quarter ended March 31, 2018, File No. 001-00973, on April 30, 2018 and incorporated herein by this reference.

(45)	Filed as Exhibit 4 with Current Report on Form 8-K, File No. 001-00973, on December 1, 1993 and incorporated herein by this reference.

(46)	Filed as Exhibit 4-6 to Registration Statement on Form S-3, File No. 333-76020, filed on December 27, 2001 and incorporated herein by this reference.

(47)	Filed as Exhibit 10.2 with Current Report on Form 8-K, File No. 001-00973, on February 19, 2009 and incorporated herein by this reference.

(48)	Filed as Exhibit 3.1 to Registration Statement on Form S-4, No. 333-69228, filed on September 10, 2001 and incorporated herein by this reference.

(49)	Filed as Exhibit 3.2 to Registration Statement on Form S-4, No. 333-69228, filed on September 10, 2001 and incorporated herein by this reference.

(50)	Filed as Exhibit 4.1 to Registration Statement on Form S-4, No. 333-69228, filed on September 10, 2001 and incorporated herein by this reference.

(51)	Filed as Exhibit 4.7 with Quarterly Report on Form 10-Q for the quarter ended March 31, 2002, File No. 000-49614, on May 15, 2002 and incorporated herein by this reference.

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(A)	Accounts Receivable written off.

(B)	Reduce reserve to appropriate level and to remove obsolete inventory.

(C)	Hudson and Mercer inventory written off.

(A)	Accounts Receivable written off.

(A)	Reduce reserve to appropriate level and to remove obsolete inventory.

(B)	Hudson and Mercer inventory written off.

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