PUBLIC SERVICE ENTERPRISE GROUP INC (Form: 10-K, Received: 02/26/2020 17:22:01)

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Table of Contents

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

——————————

FORM 10-K

(Mark One)

☒ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934

FOR THE FISCAL YEAR ENDED December 31, 2019

☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934

FOR THE TRANSITION PERIOD FROM TO



Commission File Number	Name of Registrant, Address, and Telephone Number			State or other jurisdiction of Incorporation	I.R.S. Employer Identification Number
001-09120	Public Service Enterprise Group Incorporated			New Jersey	22-2625848
	80 Park Plaza
	Newark,	New Jersey	07102
	973	430-7000

001-00973	Public Service Electric and Gas Company			New Jersey	22-1212800
	80 Park Plaza
	Newark,	New Jersey	07102
	973	430-7000

001-34232	PSEG Power LLC			Delaware	22-3663480
	80 Park Plaza
	Newark,	New Jersey	07102
	973	430-7000

Securities registered pursuant to Section 12(b) of the Act:



Title of Each Class	Trading Symbol(s)	Name of Each Exchange On Which Registered
Public Service Enterprise Group Incorporated
Common Stock without par value	PEG	New York Stock Exchange
Public Service Electric and Gas Company
9.25% First and Refunding Mortgage Bonds, Series CC, due 2021	PEG21	New York Stock Exchange
8.00% First and Refunding Mortgage Bonds, due 2037	PEG37D	New York Stock Exchange
5.00% First and Refunding Mortgage Bonds, due 2037	PEG37J	New York Stock Exchange
PSEG Power LLC
8.625% Senior Notes, due 2031	PEG31	New York Stock Exchange



Securities registered pursuant to Section 12(g) of the Act: None

(Cover continued on next page)

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(Cover continued from previous page)

Indicate by check mark whether each registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.



Public Service Enterprise Group Incorporated	☒	Yes	☐	No
Public Service Electric and Gas Company	☒	Yes	☐	No
PSEG Power LLC	☒	Yes	☐	No

Indicate by check mark if each of the registrants is not required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934. ☐ Yes ☒ No

Indicate by check mark whether each of the registrants (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports) and (2) has been subject to such filing requirements for the past 90 days. ☒ Yes ☐ No

Indicate by check mark whether the registrants have submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrants were required to submit such files) . ☒ Yes ☐ No

Indicate by check mark whether each registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.



Public Service Enterprise Group Incorporated	Large Accelerated Filer	☒	Accelerated Filer	☐	Non-accelerated Filer	☐	Smaller reporting company	☐	Emerging growth company	☐

Public Service Electric and Gas Company	Large Accelerated Filer	☐	Accelerated Filer	☐	Non-accelerated Filer	☒	Smaller reporting company	☐	Emerging growth company	☐

PSEG Power LLC	Large Accelerated Filer	☐	Accelerated Filer	☐	Non-accelerated Filer	☒	Smaller reporting company	☐	Emerging growth company	☐

If any of the registrants is an emerging growth company, indicate by check mark if such registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether any of the registrants is a shell company (as defined in Rule 12b-2 of the Exchange Act).

☐ Yes ☒ No

The aggregate market value of the Common Stock of Public Service Enterprise Group Incorporated held by non-affiliates as of June 30, 2019 was $29,513,402,185 based upon the New York Stock Exchange Composite Transaction closing price.

The number of shares outstanding of Public Service Enterprise Group Incorporated’s sole class of Common Stock as of February 21, 2020 was 505,127,221.

As of February 21, 2020, Public Service Electric and Gas Company had issued and outstanding 132,450,344 shares of Common Stock, without nominal or par value, all of which were held, beneficially and of record, by Public Service Enterprise Group Incorporated.

Public Service Electric and Gas Company and PSEG Power LLC are wholly owned subsidiaries of Public Service Enterprise Group Incorporated and each meet the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K. Each is filing its Annual Report on Form 10-K with the reduced disclosure format authorized by General Instruction I.

DOCUMENTS INCORPORATED BY REFERENCE



Part of Form 10-K of Public Service Enterprise Group Incorporated		Documents Incorporated by Reference
III		Portions of the definitive Proxy Statement for the 2020 Annual Meeting of Stockholders of Public Service Enterprise Group Incorporated, which definitive Proxy Statement is expected to be filed with the Securities and Exchange Commission on or about March 16, 2020, as specified herein.

Table of Contents

TABLE OF CONTENTS



		Page
FORWARD-LOOKING STATEMENTS		iii
FILING FORMAT		1
WHERE TO FIND MORE INFORMATION		1
PART I
Item 1.	Business	1
	Regulatory Issues	14
	Environmental Matters	21
	Information About Our Executive Officers (PSEG)	23
Item 1A.	Risk Factors	24
Item 1B.	Unresolved Staff Comments	37
Item 2.	Properties	38
Item 3.	Legal Proceedings	39
Item 4.	Mine Safety Disclosures	39
PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	39
Item 6.	Selected Financial Data	41
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	42
	Executive Overview of 2019 and Future Outlook	42
	Results of Operations	48
	Liquidity and Capital Resources	54
	Capital Requirements	58
	Off-Balance Sheet Arrangements	59
	Critical Accounting Estimates	60
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	64
Item 8.	Financial Statements and Supplementary Data	66
	Report of Independent Registered Public Accounting Firm	67
	Consolidated Financial Statements	73
	Notes to Consolidated Financial Statements
	Note 1. Organization, Basis of Presentation and Summary of Significant Accounting Policies	91
	Note 2. Recent Accounting Standards	96
	Note 3. Revenues	99
	Note 4. Early Plant Retirements/Asset Dispositions	103
	Note 5. Variable Interest Entity (VIE)	104
	Note 6. Property, Plant and Equipment and Jointly-Owned Facilities	105
	Note 7. Regulatory Assets and Liabilities	106
	Note 8. Leases	111
	Note 9. Long-Term Investments	114
	Note 10. Financing Receivables	115
	Note 11. Trust Investments	117
	Note 12. Goodwill and Other Intangibles	122
	Note 13. Asset Retirement Obligations (AROs)	123
	Note 14. Pension, Other Postretirement Benefits (OPEB) and Savings Plans	124
	Note 15. Commitments and Contingent Liabilities	133
	Note 16. Debt and Credit Facilities	140
	Note 17. Schedule of Consolidated Capital Stock	144

Table of Contents



	TABLE OF CONTENTS (continued)

	Note 18. Financial Risk Management Activities	145
	Note 19. Fair Value Measurements	149
	Note 20. Stock Based Compensation	154
	Note 21. Other Income (Deductions)	157
	Note 22. Income Taxes	158
	Note 23. Accumulated Other Comprehensive Income (Loss), Net of Tax	167
	Note 24. Earnings Per Share (EPS) and Dividends	171
	Note 25. Financial Information by Business Segment	171
	Note 26. Related-Party Transactions	173
	Note 27. Selected Quarterly Data (Unaudited)	175
	Note 28. Guarantees of Debt	176
Item 9.	Changes In and Disagreements With Accountants on Accounting and Financial Disclosure	179
Item 9A.	Controls and Procedures	179
Item 9B.	Other Information	179
PART III
Item 10.	Directors, Executive Officers and Corporate Governance	184
Item 11.	Executive Compensation	185
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	185
Item 13.	Certain Relationships and Related Transactions, and Director Independence	185
Item 14.	Principal Accounting Fees and Services	185
PART IV
Item 15.	Exhibits, Financial Statement Schedules	186
	Schedule II - Valuation and Qualifying Accounts	192
	Signatures	193

Table of Contents

FORWARD-LOOKING STATEMENTS

Certain of the matters discussed in this report about our and our subsidiaries’ future performance, including, without limitation, future revenues, earnings, strategies, prospects, consequences and all other statements that are not purely historical constitute “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. Such forward-looking statements are subject to risks and uncertainties, which could cause actual results to differ materially from those anticipated. Such statements are based on management’s beliefs as well as assumptions made by and information currently available to management. When used herein, the words “anticipate,” “intend,” “estimate,” “believe,” “expect,” “plan,” “should,” “hypothetical,” “potential,” “forecast,” “project,” variations of such words and similar expressions are intended to identify forward-looking statements. Factors that may cause actual results to differ are often presented with the forward-looking statements themselves. Other factors that could cause actual results to differ materially from those contemplated in any forward-looking statements made by us herein are discussed in Item 1A. Risk Factors, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A), Item 8. Financial Statements and Supplementary Data—Note 15. Commitments and Contingent Liabilities, and other filings we make with the United States Securities and Exchange Commission (SEC), including our subsequent reports on Form 10-Q and Form 8-K. These factors include, but are not limited to:


•	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;

iii

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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.

All of the forward-looking statements made in this report are qualified by these cautionary statements and we cannot assure you that the results or developments anticipated by management will be realized or even if realized, will have the expected consequences to, or effects on, us or our business, prospects, financial condition, results of operations or cash flows. Readers are cautioned not to place undue reliance on these forward-looking statements in making any investment decision. Forward-looking statements made in this report apply only as of the date of this report. While we may elect to update forward-looking statements from time to time, we specifically disclaim any obligation to do so, even in light of new information or future events, unless otherwise required by applicable securities laws.

The forward-looking statements contained in this report are intended to qualify for the safe harbor provisions of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended.

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FILING FORMAT

This combined Annual Report on Form 10-K is separately filed by Public Service Enterprise Group Incorporated (PSEG), Public Service Electric and Gas Company (PSE&G) and PSEG Power LLC (PSEG Power). Information relating to any individual company is filed by such company on its own behalf. PSE&G and PSEG Power are each only responsible for information about itself and its subsidiaries.

Discussions throughout the document refer to PSEG and its direct operating subsidiaries, PSE&G and PSEG Power. Depending on the context of each section, references to “we,” “us,” and “our” relate to PSEG or to the specific company or companies being discussed.

WHERE TO FIND MORE INFORMATION

We file annual, quarterly and current reports, proxy statements and other information with the SEC. You may obtain our filed documents from commercial document retrieval services, the SEC’s internet website at www.sec.gov or our website at investor.pseg.com. Information on our website should not be deemed incorporated into or as a part of this report. Our Common Stock is listed on the New York Stock Exchange under the trading symbol PEG. You can obtain information about us at the offices of the New York Stock Exchange, Inc., 11 Wall Street, New York, New York 10005.

PART I

ITEM 1. BUSINESS

We were incorporated under the laws of the State of New Jersey in 1985 and our principal executive offices are located at 80 Park Plaza, Newark, New Jersey 07102. We 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, 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:

•

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.

Federal—NERC, at the direction of FERC, has implemented national and regional reliability standards to ensure the reliability of the grid and to prevent major system blackouts. NERC 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

CO₂ 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 CO₂emission 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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ITEM 1A. RISK FACTORS

The following factors should be considered when reviewing our business. These factors could have a material adverse impact on our business, prospects, financial position, results of operations or cash flows and could cause results to differ materially from those expressed elsewhere in this report.

MARKET AND COMPETITION RISKS

Fluctuations in the wholesale power and natural gas markets could negatively affect our financial condition, results of operations and cash flows.

In the markets where we operate, natural gas prices have a major impact on the price that generators receive for their output. Over the past several years, wholesale prices for natural gas have remained well below the peak levels experienced in 2008, in part due to increased shale gas production as extraction technology has improved. Lower gas prices have resulted in lower electricity prices, which have reduced our margins as nuclear generation costs have not declined similarly.

We may be unable to obtain an adequate fuel supply in the future.

We obtain substantially all of our physical natural gas and nuclear fuel supply from third parties pursuant to arrangements that vary in term, pricing structure, firmness and delivery flexibility. Our fuel supply arrangements must be coordinated with transportation agreements, balancing agreements, storage services and other contracts to ensure that the natural gas and nuclear fuel are delivered to our power plants at the times, in the quantities and otherwise in a manner that meets the needs of our generation portfolio and our customers. We must also comply with laws and regulations governing the transportation of such fuels.

We are exposed to increases in the price of natural gas and nuclear fuel, and it is possible that sufficient supplies to operate our generating facilities profitably may not continue to be available to us. Significant changes in the price of natural gas and nuclear fuel could affect our future results and impact our liquidity needs. In addition, we face risks with regard to the delivery to, and the use of natural gas and nuclear fuel by, our power plants including the following:


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


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


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


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


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


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


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


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

Our nuclear units have a diversified portfolio of contracts and inventory that provide a substantial portion of our fuel raw material needs over the next several years. However, each of our nuclear units has contracted with a single fuel fabrication services provider, and transitioning to an alternative provider could take an extended period of time. Certain of our other generation facilities also require fuel or other services that may only be available from one or a limited number of suppliers. The availability and price of this fuel may vary due to supplier financial or operational disruptions, transportation disruptions and force majeure. At times, such fuel may not be available at any price, or we may not be able to transport it to our facilities on a timely basis. In this case, we may not be able to run those facilities even if it would be profitable. If we had sold forward the power from such a facility, we could be required to supply or purchase power from alternate sources, perhaps at a loss. This could have a material adverse impact on our business, the financial results of specific plants and on our results of operations.

Although our fuel contract portfolio provides a degree of hedging against these market risks, such hedging may not be effective and future increases in our fuel costs could materially and adversely affect our liquidity, financial condition and results of

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operations. While our generation runs on a mix of fuels, primarily natural gas and nuclear fuel, an increase in the cost of any particular fuel ultimately used could impact our results of operations.

Operation of our generating stations are subject to market risks that are beyond our control.

Generation output will either be used to satisfy wholesale contract requirements or other bilateral contracts or be sold into competitive power markets. Participants in the competitive power markets are not guaranteed any specified rate of return on their capital investments. Generation revenues and results of operations are dependent upon prevailing market prices for energy, capacity, ancillary services and fuel supply in the markets served. Changes in prevailing market prices could have a material adverse effect on our financial condition and results of operations.

Factors that may cause market price fluctuations include:


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


•	power transmission or fuel transportation capacity constraints or inefficiencies;


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


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


•	seasonal fluctuations;


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


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


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


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


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

Our generation business frequently involves the establishment of forward sale positions in the wholesale energy markets on long-term and short-term bases. To the extent that we have produced or purchased energy in excess of our contracted obligations, a reduction in market prices could reduce profitability. Conversely, to the extent that we have contracted obligations in excess of energy we have produced or purchased, an increase in market prices could reduce profitability. If the strategy we utilize to hedge our exposure to these various risks or if our internal policies and procedures designed to monitor the exposure to these various risks are not effective, we could incur material losses. Our market positions can also be adversely affected by the level of volatility in the energy markets that, in turn, depends on various factors, including weather in various geographical areas, short-term supply and demand imbalances, customer migration and pricing differentials at various geographic locations. These risks cannot be predicted with certainty.

Increases in market prices also affect our ability to hedge generation output and fuel requirements as the obligation to post margin increases with increasing prices.

We face significant competition in the wholesale energy and capacity markets.

Our wholesale power and marketing businesses are subject to significant competition that may adversely affect our ability to make investments or sales on favorable terms and achieve our business objectives. Increased competition could contribute to a reduction in prices offered for power and could result in lower earnings and cash flows. A decline in market liquidity could also negatively impact financial results. Regulatory, environmental, industry and other operational developments will have a significant impact on our ability to compete in energy and capacity markets, potentially resulting in erosion of our market share and impairment in the value of our power plants. Certain states have taken, or are considering taking, actions to subsidize or otherwise provide economic support to renewables, energy efficiency initiatives and existing, uneconomic generation facilities that could adversely affect capacity and energy prices. Increased generation supply and lower energy prices due to these subsidies could have an adverse impact on our results of operations.

The introduction or expansion of technologies related to energy generation, distribution and consumption and changes in customer usage patterns could adversely impact us.

The power generation business has seen a substantial change in the technologies used to produce power. Newer generation facilities are often more efficient than aging facilities, which may put some of these older facilities at a competitive disadvantage to the extent newer facilities are able to consume the same or less fuel to achieve a higher level of generation output. Federal and state incentives for the development and production of renewable sources of power have facilitated the penetration of competing technologies, such as wind, solar, and commercial-sized power storage. Additionally, the development of DSM and energy efficiency programs can impact demand requirements for some of our markets at certain times during the year. The continued development of subsidized, competing power generation technologies and significant development of DSM

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and energy efficiency programs could alter the market and price structure for power generation and could result in a reduction in load requirements, negatively impacting our financial condition, results of operations and cash flows. Technological advances driven by federal laws mandating new levels of energy efficiency in end-use electric devices or other improvements in, or applications of, technology could also lead to declines in per capita energy consumption.

Advances in distributed generation technologies, such as fuel cells, micro turbines, micro grids, windmills and net-metered solar installations, may reduce the cost of alternative methods of producing electricity to a level that is competitive with that of most central station electric production. Large customers, such as universities and hospitals, continue to explore potential micro grid installation. Certain states, such as Massachusetts and California, are also considering mandating the use of power storage resources to replace uneconomic or retiring generation facilities. Such developments could (i) affect the price of energy, (ii) reduce energy deliveries as customer-owned generation becomes more cost-effective, (iii) require further improvements to our distribution systems to address changing load demands, and (iv) make portions of our transmission and/or distribution facilities obsolete prior to the end of their useful lives. These technologies could also result in further declines in commodity prices or demand for delivered energy.

Some or all of these factors could result in a lack of growth or decline in customer demand for electricity or number of customers, and may cause us to fail to fully realize anticipated benefits from significant capital investments and expenditures, which could have a material adverse effect on our financial position, results of operations and cash flows. These factors could also materially affect our results of operations, cash flows or financial positions through, among other things, reduced operating revenues, increased operating and maintenance expenses, and increased capital expenditures, as well as potential asset impairment charges or accelerated depreciation and decommissioning expenses over shortened remaining asset useful lives.

Economic downturns would likely have a material adverse effect on our businesses.

Our results of operations may be negatively affected by sustained downturns or sluggishness in the economy, including low levels in the market prices for power, generation capacity and natural gas, which can fluctuate substantially. Increased unemployment of residential customers and decreased demand for products and services provided by C&I customers resulting from an economic downturn could lead to declines in the demand for energy and an increase in the number of uncollectible customer balances, which would negatively impact our overall sales and cash flows. Although our utility business is subject to regulated allowable rates of return, overall declines in electricity and gas sold could materially adversely affect our financial condition, results of operations and cash flows. Additionally, prolonged economic downturns that negatively impact our financial condition, results of operations and cash flows could result in future material impairment charges to write down the carrying value of certain assets to their respective fair values.

We are subject to third-party credit risk relating to our sale of generation output and purchase of fuel.

We sell generation output and buy fuel through the execution of bilateral contracts. We also seek to contract in advance for a significant proportion of our anticipated output capacity and fuel needs. These contracts are subject to credit risk, which relates to the ability of our counterparties to meet their contractual obligations to us. Any failure of these counterparties to perform could require PSEG Power to purchase or sell energy or fuel in the wholesale markets at less favorable prices and incur additional losses, which could have a material adverse impact on our results of operations, cash flows and financial position. In the spot markets, we are exposed to the risks of the default sharing mechanisms that exist in those markets, some of which attempt to spread the risk across all participants. Therefore, a default by a third party could increase our costs, which could negatively impact our results of operations and cash flows.

Financial market performance directly affects the asset values of our nuclear decommissioning trust (NDT) Fund and defined benefit plan trust funds. Market performance and other factors could decrease the value of trust assets and could result in the need for significant additional funding.

The performance of the financial markets will affect the value of the assets that are held in trust to satisfy our future obligations under our defined benefit plans and to decommission our nuclear generating plants. A decline in the market value of our NDT Fund could increase PSEG Power’s funding requirements to decommission its nuclear plants. A decline in the market value of the defined benefit plan trust funds could increase our pension plan funding requirements. The market value of our trusts could be negatively impacted by decreases in the rate of return on trust assets, decreased interest rates used to measure the required minimum funding levels and future government regulation. Additional funding requirements for our defined benefit plans could be caused by changes in required or voluntary contributions, an increase in the number of employees becoming eligible to retire and changes in life expectancy assumptions. Increased costs could also lead to additional funding requirements for our decommissioning trust. Failure to adequately manage our investments in our NDT Fund and defined benefit plan trusts could result in the need for us to make significant cash contributions in the future to maintain our funding at sufficient levels, which would negatively impact our results of operations, cash flows and financial position.

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REGULATORY, LEGISLATIVE AND LEGAL RISKS

PSE&G’s revenues, earnings and results of operations are dependent upon state laws and regulations that affect distribution and related activities.

PSE&G is subject to regulation by the BPU. Such regulation affects almost every aspect of its businesses, including its retail rates, and failure to comply with these regulations could have a material adverse impact on PSE&G’s ability to operate its business and could result in fines, penalties or sanctions. The retail rates for electric and gas distribution services are established in a base rate proceeding and remain in effect until a new base rate proceeding is filed and concluded. In addition, our utility has received approval for several clause recovery mechanisms, some of which provide for recovery of costs and earn returns on authorized investments. These clause mechanisms require periodic updates to be reviewed and approved by the BPU and are subject to prudency reviews. Inability to obtain fair or timely recovery of all our costs, including a return of, or on, our investments in rates, could have a material adverse impact on our results of operations and cash flows. In addition, if legislative and regulatory structures were to evolve in such a way that PSE&G’s exclusive rights to serve its regulated customers were eroded, its future earnings could be negatively impacted.

The BPU also conducts periodic combined management/competitive service audits of New Jersey utilities related to affiliate standard requirements, competitive services, cross-subsidization, cost allocation and other issues. A finding by the BPU of non-compliance with these requirements could result in fines, a reduction in PSE&G’s authorized base rate or the disallowance of the recovery of certain costs, which could have a material adverse impact on our business, results of operations and cash flows.

In addition, PSE&G procures the supply requirements of its default service BGSS gas customers through a full-requirements contract with PSEG Power. Government officials, legislators and advocacy groups are aware of the affiliation between PSE&G and PSEG Power. In periods of rising utility rates, those officials and advocacy groups may question or challenge costs and transactions incurred by PSE&G with PSEG Power, irrespective of any previous regulatory processes or approvals underlying those transactions. The occurrence of such challenges may subject PSEG Power to a level of scrutiny not faced by other unaffiliated competitors in those markets and could adversely affect retail rates received by PSE&G in an effort to offset any perceived benefit to PSEG Power from the affiliation.

PSE&G’s proposed investment programs may not be fully approved by regulators, which could result in lower than desired service levels to customers, and actual capital investment by PSE&G may be lower than planned, which would cause lower than anticipated rate base.

PSE&G is a regulated public utility that operates and invests in an electric T&D system and a gas distribution system as well as certain regulated clean energy investments, including solar and energy efficiency within New Jersey. PSE&G invests in capital projects to maintain and improve its existing T&D system and to address various public policy goals and meet customer expectations. Transmission projects are subject to review in the FERC-approved PJM transmission expansion process while distribution and clean energy projects are subject to approval by the BPU. We cannot be certain that any proposed project will be approved as requested or at all. In particular, PSE&G is currently seeking approval for a number of investment programs from the BPU including our proposed CEF program, a six-year estimated $3.5 billion investment program covering energy efficiency (CEF-EE), energy cloud (CEF-EC) and electric vehicles and energy storage (CEF EV/ES) programs. The BPU is reviewing the CEF-EE program concurrently with its efforts related to implementing provisions of the Clean Energy Act related to energy efficiency. Additionally, New Jersey released its EMP in January 2020, which is supportive of energy efficiency but gives the BPU discretion in implementation between state-and utility-operated programs. In February 2020, PSE&G reached an agreement with parties in the CEF-EE matter which was approved by the BPU to extend the timeline for review of the CEF-EE filing through September 2020. In addition, the BPU has circulated to the parties procedural schedules for the CEF-EC, CEF-EV and CEF-ES programs. If these programs and other programs that PSE&G may file from time to time are only approved in part, or not at all, or if the approval fails to allow for the timely recovery of all of PSE&G’s costs, including a return of, or on, its investment, PSE&G will have a lower than anticipated rate base, thus causing its future earnings to be lower than anticipated. If these programs are not approved, that could also adversely affect our service levels for customers. Further, the BPU could take positions to exclude or limit utility participation in certain areas, such as renewable generation, energy efficiency, electric vehicle infrastructure and energy storage, which would limit our relationship with customers and narrow our future growth prospects.

We are subject to comprehensive federal regulation that affects, or may affect, our businesses.

We are subject to regulation by federal authorities. Such regulation affects almost every aspect of our businesses, including management and operations; the terms and rates of transmission services; investment strategies; the financing of our operations and the payment of dividends. Failure to comply with these regulations could have a material adverse impact on our ability to operate our business and could result in fines, penalties or sanctions.

Recovery of wholesale transmission rates—PSE&G’s wholesale transmission rates are regulated by FERC and are recovered through a FERC-approved formula rate. The revenue requirements are reset each year through this formula.

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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 MISO transmission owners and found these ROEs to be unjust and unreasonable. Other ROE complaints have been pending before FERC regarding the ISO New England Inc. Transmission Owners and utilities in other jurisdictions.

In addition, transmission ROEs have recently become the target of certain state utility commissions, municipal utilities, consumer advocates and consumer groups seeking to lower customer rates. These agencies and groups have filed complaints with FERC asking to reduce the base ROE of various transmission owners. They point to changes in the capital markets as justification for lowering the ROE of these companies. While we are not the subject of any of these complaints, they could set a precedent for FERC-regulated transmission owners, such as PSE&G. Changes to FERC’s transmission ROE policy and challenges by FERC, the BPU or other constituencies to our base transmission ROE could limit our ability to obtain fair or timely recovery of all our costs, including a return of or on our investments in rates, which could have a material adverse impact on our business, financial condition, results of operations and cash flows.

NERC Compliance—NERC, at the direction of FERC, has implemented mandatory NERC Operations and CIP standards to ensure the reliability of the U.S. Bulk Electric System, which includes electric transmission and generation systems, and to prevent major system black-outs. NERC CIP standards establish cybersecurity and physical security protections for critical systems and facilities. We have been, and will continue to be, periodically audited by NERC for compliance and are subject to penalties for non-compliance with applicable NERC standards. An audit of PSE&G’s compliance with CIP physical and cybersecurity standards was performed in the fourth quarter of 2018, the results of which are under review. We cannot determine what actions, if any, NERC or FERC may take. Failure to comply with such standards could result in penalties or increased costs to bring such facilities into compliance. Such penalties and costs, as well as lost revenue from prolonged outages required to bring facilities into compliance with these standards, could materially adversely impact our business, results of operations and cash flows.

MBR Authority and Other Regulatory Approvals—Under FERC regulations, public utilities that wish to sell power at market rates must receive MBR Authority before making power sales, and the majority of our businesses operate with such authority. Failure to maintain MBR authorization, or the effects of any severe mitigation measures that may be required if market power was evaluated differently in the future, could have a material adverse effect on our business, financial condition and results of operations.

Oversight by the CFTC relating to derivative transactions—The CFTC has regulatory oversight of the swap and futures markets and options, including energy trading, and licensed futures professionals such as brokers, clearing members and large traders. Changes to regulations or adoption of additional regulations by the CFTC, including any regulations relating to position limits on futures and other derivatives or margin for derivatives and increased investigations by the CFTC, could negatively impact PSEG Power’s ability to hedge its portfolio in an efficient, cost-effective manner by, among other things, potentially decreasing liquidity in the forward commodity and derivatives markets or limiting PSEG Power’s ability to utilize non-cash collateral for derivatives transactions.

We may also be required to obtain various other regulatory approvals to, among other things, buy or sell assets, engage in transactions between our public utility and our other subsidiaries, and, in some cases, enter into financing arrangements, issue securities and allow our subsidiaries to pay dividends. Failure to obtain these approvals on a timely basis could materially adversely affect our results of operations and cash flows.

Our New Jersey nuclear plants may not be awarded ZECs in future periods, or the current or subsequent ZEC program periods could be materially adversely modified through legal proceedings, either of which could result in the retirement of all of these nuclear plants.

In April 2019, PSEG Power’s Salem 1, Salem 2 and Hope Creek nuclear plants were awarded ZECs by the BPU. The BPU’s decision awarding ZECs has been appealed by the Division of Rate Counsel. We cannot predict the outcome of this matter. The nuclear plants are expected to receive ZEC revenue for approximately three years, through May 2022, and will be obligated to maintain operations during that period, subject to exceptions specified in the ZEC legislation. The ZEC legislation requires nuclear plants to reapply for any subsequent three-year periods.

In the event that (i) the ZEC program is overturned or otherwise materially adversely modified through legal process, (ii) the terms and conditions of the subsequent period under the ZEC program, including the amount of ZEC payments that may be awarded, materially differ from those of the current ZEC period, or (iii) any of the Salem 1, Salem 2 and Hope Creek plants is not awarded ZEC payments by the BPU and does not otherwise experience a material financial change, PSEG Power will take all necessary steps to retire all of these plants subsequent to the initial ZEC period at or prior to a scheduled refueling outage. Alternatively, if all of the Salem 1, Salem 2 and Hope Creek plants are selected to continue to receive ZEC payments but the financial condition of the plants is materially adversely impacted by changes in commodity prices, FERC’s changes to the capacity market construct (absent sufficient capacity revenues provided under a program approved by the BPU in accordance with a FERC-authorized capacity mechanism), or, in the case of the Salem nuclear plants, decisions by the EPA and state environmental regulators regarding the implementation of Section 316(b) of the CWA and related state regulations, or other

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factors, PSEG Power would still take all necessary steps to retire all of these plants. The costs and accounting charges associated with any such retirement, which may include, among other things, accelerated depreciation and amortization or impairment charges, potential penalties associated with the early termination of capacity obligations and fuel contracts, accelerated asset retirement costs, severance costs, environmental remediation costs and, in certain circumstances, potential additional funding of the NDT Fund, would be material to both PSEG and PSEG Power.

We may be adversely affected by changes in energy regulatory policies, including energy and capacity market design rules and developments affecting transmission.

The energy industry continues to be regulated and the rules to which our businesses are subject are always at risk of being changed. Our business has been impacted by established rules that create locational capacity markets in each of PJM, ISO-NE and NYISO. Under these rules, generators located in constrained areas are paid more for their capacity so there is an incentive to locate in those areas where generation capacity is most needed. PJM’s capacity market design rules and ISO-NE’s FCM rules continue to evolve, most recently in response to efforts to integrate public policy initiatives into the wholesale markets. In particular, in December 2019, FERC issued an order establishing new rules for PJM’s capacity market whereby FERC extended the PJM MOPR to include both new and existing resources that receive or are entitled to receive, certain out-of-market payments, with certain exemptions. States that have clean energy programs designed to achieve public policy goals can still choose to utilize the existing FRR approach, which provides a means other than PJM’s capacity auction for a generation resource to satisfy its capacity obligation.

PSEG Power’s New Jersey nuclear plants that receive ZEC payments will be subject to the new MOPR. Due to the lack of clarity regarding certain aspects of the MOPR, PSEG cannot at this time estimate the impact of the MOPR on the capacity markets or the nuclear units. In addition, PSEG cannot predict whether there will be challenges to the FERC order and, if so, the impact of such challenges on the MOPR and other capacity market rules. These and further changes to capacity market rules may have an adverse impact on our financial condition, results of operations and cash flows.

Further, some of the market-based mechanisms in which we participate, including BGS auctions, are at times the subject of review or discussion by some of the participants in the New Jersey and federal arenas. We can provide no assurance that these mechanisms will continue to exist in their current form, nor otherwise be modified.

To the extent that additions to the transmission system relieve or reduce congestion in eastern PJM where most of our plants are located, PSEG Power’s capacity and energy revenues could be adversely affected. Moreover, through changes encouraged by FERC to transmission planning processes, or through RTO/ISO initiatives to change their planning processes, more transmission may ultimately be built to facilitate renewable generation or support other public policy initiatives. Any such addition to the transmission system could have a material adverse impact on our financial condition and results of operations.

State and federal actions aimed at combating the effects of climate change could have a material adverse effect on our business and could result in stranded assets.

State and federal government agencies have proposed a number of rules and initiatives intended to combat the effects of climate change. In particular, in January 2020, the State of New Jersey released its EMP which 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. In addition, in June 2019, the EPA issued its final ACE rule as a replacement for the repealed Clean Power Plan, a greenhouse gas emission regulation for existing power plants.

These actions by state and federal government agencies and similar actions that may be taken in the future could result in reduced reliance on natural gas and could potentially result in stranding natural gas assets owned and operated by PSEG Power and PSE&G, which could materially adversely affect our business, financial condition and results of operations.

Our ownership and operation of nuclear power plants involve regulatory risks as well as financial, environmental and health and safety risks.

Approximately half of our total generation output each year is provided by our nuclear fleet. For this reason, we are exposed to risks related to the continued successful operation of our nuclear facilities and issues that may adversely affect the nuclear generation industry. In addition to the risk of retirement discussed below, risks associated with the operation of nuclear facilities include:

Storage and Disposal of Spent Nuclear Fuel—Federal law requires the DOE to provide for the permanent storage of spent nuclear fuel but the DOE has not yet begun accepting spent nuclear fuel. Until a federal site is available, we use on-site storage for spent nuclear fuel, which is reimbursed by the DOE. However, future capital expenditures may be required to increase spent fuel storage capacity at our nuclear facilities. Once a federal site is available, the DOE may impose fees to support a permanent repository. In addition, the on-site storage for spent nuclear fuel may significantly increase the decommissioning costs of our nuclear units.

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Regulatory and Legal Risk—We may be required to substantially increase capital expenditures or operating or decommissioning costs at our nuclear facilities to the extent there is a change in the Atomic Energy Act or the applicable regulations, trade controls or the environmental rules and regulations applicable to nuclear facilities; a modification, suspension or revocation of licenses issued by the NRC; the imposition of civil penalties for failure to comply with the Atomic Energy Act, related regulations, trade controls or the terms and conditions of the licenses for nuclear generating facilities; or the shutdown of one of our nuclear facilities. Any such event could have a material adverse effect on our financial condition or results of operations.

Operational Risk—Operations at any of our nuclear facilities could degrade to the point where an affected unit needs to be shut down or operated at less than full capacity. If this were to happen, identifying and correcting the causes may require significant time and expense. Any significant outages could result in reduced earnings as we would have less electric output to sell.

In addition, if a unit cannot be operated through the end of its current estimated useful life, our results of operations could be adversely affected by increased depreciation rates, impairment charges and accelerated future decommissioning costs.

Nuclear Incident or Accident Risk—Accidents and other unforeseen problems have occurred at nuclear stations, both in the U.S. and elsewhere. The consequences of an accident can be severe and may include loss of life, significant property damage and/or a change in the regulatory climate. We have nuclear units at two sites. It is possible that an accident or other incident at a nuclear generating unit could adversely affect our ability to continue to operate unaffected units located at the same site, which would further affect our financial condition, results of operations and cash flows. An accident or incident at a nuclear unit not owned by us could lead to increased regulation, which could affect our ability to continue to economically operate our units. Any resulting financial impact from a nuclear accident may exceed our resources, including insurance coverages. Further, as a licensed nuclear operator subject to the Price-Anderson Act and a member of a nuclear industry mutual insurance company, PSEG Power is subject to potential retroactive assessments as a result of an industry nuclear incident or retrospective premiums due to adverse industry loss experience and such assessments may be material.

In the event of non-compliance with applicable legislation, regulation and licenses, the NRC may increase regulatory oversight, impose fines, and/or shut down a unit, depending on its assessment of the severity of the non-compliance. If a serious nuclear incident were to occur, our business, reputation, financial condition and results of operations could be materially adversely affected. In each case, the amount and types of insurance available to cover losses that might arise in connection with the operation of our nuclear fleet are limited and may be insufficient to cover any costs we may incur.

Decommissioning—NRC regulations require that licensees of nuclear generating facilities demonstrate reasonable assurance that funds will be available to decommission a nuclear facility at the end of its useful life. PSEG Nuclear has established an NDT Fund to satisfy these obligations. However, forecasting trust fund investment earnings and costs to decommission nuclear generating stations requires significant judgment, and actual results could differ significantly from current estimates. If we determine that it is necessary to retire one of our nuclear generating stations before the end of its useful life, there is a risk that it will no longer meet the NRC minimum funding requirements due to the earlier commencement of decommissioning activities and a shorter time period over which the NDT investments could appreciate in value. A shortfall could require PSEG to post parental guarantees or make additional cash contributions to ensure that the NDT Fund continues to satisfy the NRC minimum funding requirements. As a result, our financial position or cash flows could be significantly adversely affected.

We are subject to numerous federal, state and local environmental laws and regulations that may significantly limit or affect our businesses, adversely impact our business plans or expose us to significant environmental fines and liabilities.

We are subject to extensive federal, state and local environmental laws and regulations regarding air quality, water quality, site remediation, land use, waste disposal, the impact of climate change, natural resources damages and other matters. These laws and regulations affect how we conduct our operations and make capital expenditures. There have been a number of recent changes to existing environmental laws and regulations and this trend may continue. Changes in these laws, or violations of laws, could result in significant increases in our compliance costs, capital expenditures to bring our facilities into compliance, operating costs for remediation and clean-up actions, civil penalties or damages from actions brought by third parties for alleged health or property damages. Any such increase in our costs could have a material impact on our financial condition, results of operations and cash flows and could require further economic review to determine whether to continue operations or decommission an affected facility. We may also be unable to successfully recover certain of these cost increases through our existing regulatory rate structures, in the case of PSE&G, or our contracts with our customers, in the case of PSEG Power.

Environmental laws and regulations have generally become more stringent over time, and this trend is likely to continue. In particular:

Concerns over global climate change could result in laws and regulations to limit CO₂ emissions or other GHG emissions produced by our fossil generation facilities—Federal and state legislation and regulation designed to address global climate change through the reduction of GHG emissions could materially impact our fossil generation facilities. As of January 1, 2020, New Jersey officially re-entered RGGI. The NJDEP is currently in the process of revising its rules to implement the intricacies of that program. This may have cost implications for our fossil generation facilities. Such expenditures could materially affect the continued economic viability of one or more such facilities. In addition to legislative and regulatory initiatives, the outcome

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of certain legal proceedings regarding alleged impacts of global climate change not involving us could be material to the future liability of energy companies. If relevant federal or state common law were to develop that imposed liability upon those that emit GHGs for alleged impacts of GHGs emissions, such potential liability to our fossil generation operations could be material.

Potential closed-cycle cooling requirements—In 2014, the EPA finalized rules regarding the regulation of cooling water intake structures. The EPA has structured the rule so that each state will continue to consider renewal permits for existing power facilities on a case by case basis. The rule requires that facilities seeking permit renewals conduct a wide range of studies related to impingement mortality and entrainment and submit the results with their permit applications. State actions to renew permits under the provisions of this rule are ongoing at this time.

If the NJDEP or the Connecticut Department of Energy and Environmental Protection were to require installation of closed-cycle cooling or its equivalent at any of our Salem or New Haven generating stations, the related increased costs and impacts would be material to our financial position, results of operations and cash flows and would require further economic review to determine whether to continue operations or decommission any such station.

Remediation of environmental contamination at current or formerly-owned facilities—We are subject to liability under environmental laws for the costs of remediating environmental contamination of property now or formerly owned by us and of property contaminated by hazardous substances that we generated. Remediation activities associated with our former manufactured gas plant (MGP) operations are one source of such costs. In addition, the historic operations of our companies and the operations of numerous other companies along the Passaic and Hackensack Rivers are alleged by Federal and State agencies to have discharged substantial contamination into the Passaic River/Newark Bay Complex in violation of various statutes. The EPA is also evaluating the Hackensack River, a tributary to Newark Bay, for inclusion in the Superfund program. We are also involved in a number of proceedings relating to sites where other hazardous substances may have been discharged and may be subject to additional proceedings in the future, regardless of the absence of fault or any contractual agreements between private parties, the related costs of which could have a material adverse effect on our financial condition, results of operations and cash flows. New Jersey law places affirmative obligations on us to investigate and, if necessary, remediate contaminated property upon which we were in any way responsible for a discharge of hazardous substances, impacting the speed by which we will need to investigate contaminated properties, which could adversely impact cash flows. We cannot predict what further actions, if any, or the costs or the timing thereof, that may be required with respect to these or other natural resource damages claims. However, exposure to natural resource damages could subject us to additional potentially material liability. For a discussion of these and other environmental matters, see Item 8. Note 15. Commitments and Contingent Liabilities.

We may not receive necessary licenses and permits in a timely manner or at all, which could adversely impact our business and results of operations.

We must periodically apply for licenses and permits from various regulatory authorities, including environmental regulatory authorities, and abide by their respective orders. Delay in obtaining, or failure to obtain and maintain, any permits or approvals, including environmental permits or approvals, or delay in or failure to satisfy any applicable regulatory requirements, could:


•	prevent construction of new facilities,


•	limit or prevent continued operation of existing facilities,


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


•	result in significant additional costs,

each of which could materially affect our business, financial condition, results of operations and cash flows. In addition, the process of obtaining licenses and permits from regulatory authorities may be delayed or defeated by concerted community opposition and such delay or defeat could have a material effect on our business.

PSE&G periodically files base rate proceedings. Such proceedings are at times contentious, lengthy and subject to appeal, which could lead to uncertainty as to the ultimate results and which could introduce time delays in effectuating rate changes.

PSE&G periodically files base rate proceedings with the BPU, and we are required to file our next distribution rate case no later than December 2023. These proceedings typically involve multiple parties, including governmental bodies and officials, consumer advocacy groups and various consumers of energy, who have differing concerns but who have the common objective of limiting rate increases or even reducing rates. The proceedings generally have timelines that may not be limited by statute. Decisions are subject to appeal, potentially leading to additional uncertainty associated with the approval proceedings. The potential duration of such proceedings creates a risk that rates ultimately approved by the applicable regulatory body may not be sufficient for PSE&G to recover its costs by the time the rates become effective. Established rates are also subject to subsequent reviews by state regulators, whereby various portions of rates could be adjusted, including recovery mechanisms for costs associated with the procurement of electricity or gas, bad debt, MGP remediation, smart grid infrastructure and energy

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efficiency, DR and renewable energy programs. If future base rate proceedings are protracted or result in approved rates that do not allow PSE&G to fully recover its costs or result in ROEs that are below historical levels, our financial condition, results of operations and cash flows would be materially adversely impacted.

Efforts designed to promote and expand the use of energy efficiency measures and distributed generation technologies, such as rooftop solar and battery storage, in PSE&G’s service territories could result in customers leaving the electric distribution system and an increase in customer net energy metering. Over time, customer adoption of these and other technologies and increased energy efficiency could adversely impact PSE&G’s revenue and ability to fully recover its costs, which could require PSE&G to pursue a rate proceeding to adjust revenue requirements or seek recovery though other mechanisms.

We cannot predict the outcome of any legal, regulatory or other proceeding, settlement, investigation or claim relating to our business activities. An adverse determination could negatively impact our financial condition, results of operations and cash flows.

From time to time we are involved in legal, regulatory and other proceedings or claims arising out of our business operations, the most significant of which are summarized in Item 8. Note 15. Commitments and Contingent Liabilities. Adverse outcomes in any of these proceedings could require significant expenditures that could have a material adverse effect on our financial condition, results of operations and cash flows.

Changes in tax law and regulation and the inherent difficulty in quantifying potential tax effects of business decisions could negatively impact our results of operations and cash flows.

We are subject to federal tax laws and the tax laws of the states in which we operate, including rules and interpretations promulgated by the applicable taxing authorities. Significant changes to the tax laws, rules and interpretations applicable to our businesses, including income inclusions, deductions and other changes that may impact investment incentives could have a material impact on our results of operations and cash flows.

In addition, we are required to make judgments in order to estimate our obligations to taxing authorities. These tax obligations include income, real estate, sales and use and employment-related taxes. These judgments can include reserves for potential adverse outcomes regarding tax positions that have been taken that could be subject to challenge by the tax authorities. If our actual tax obligations materially differ from our estimated obligations, our results of operations and cash flows could be materially adversely affected.

OPERATIONAL RISKS

Because PSEG is a holding company, its ability to meet its corporate funding needs, service debt and pay dividends could be limited.

PSEG is a holding company with no material assets other than the interests of its subsidiaries. Accordingly, all of the operations of PSEG are conducted by its subsidiaries, which are separate and distinct legal entities that have no obligation, contingent or otherwise, to pay the debt of PSEG or to make any funds available to PSEG to pay such debt or satisfy its other corporate funding needs. These corporate funding needs include PSEG’s operating expenses, the payment of interest on and principal of its outstanding indebtedness and the payment of dividends on its capital stock. As a result, PSEG can give no assurances that its subsidiaries will be able to transfer funds to PSEG to meet all of these obligations.

Lack of growth or slower growth in the number of customers, or a decline in customer demand, could adversely impact our financial condition, results of operations and cash flows.

Growth in customer accounts and growth of customer usage each directly influence the demand for electricity and the need for additional generation, transmission and distribution facilities. Customer growth and customer usage may be affected by a number of factors, including:


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


•	regulatory 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.

Some or all of these factors could result in a lack of growth or decline in customer demand for electricity and may prevent us from fully realizing the benefits from significant capital investments and expenditures, which could have a material adverse effect on our financial position, results of operations and cash flows.

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There may be periods when PSEG Power may not be able to meet its commitments under forward sale obligations at a reasonable cost or at all.

A substantial portion of PSEG Power’s base load generation output has been sold forward under fixed price power sales contracts and PSEG Power also sells forward the output from its intermediate and peaking facilities when it deems it commercially advantageous to do so. Our forward sales of energy and capacity assume sustained, acceptable levels of operating performance. This is especially important at our lower-cost facilities. Operations at any of our plants could degrade to the point where the plant has to shut down or operate at less than full capacity. Some issues that could impact the operation of our facilities are:


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


•	disruptions in the transmission of electricity;


•	labor disputes or work stoppages;


•	fuel supply interruptions;


•	transportation constraints;


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


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

Identifying and correcting any of these issues may require significant time and expense. Depending on the materiality of the issue, we may choose to close a plant rather than incur the expense of restarting it or returning it to full capacity.

Because the obligations under most of these forward sale agreements are not contingent on a unit being available to generate power, PSEG Power is generally required to deliver power to the buyer even in the event of a plant outage, fuel supply disruption or a reduction in the available capacity of the unit. To the extent that PSEG Power does not have sufficient lower cost capacity to meet its commitments under its forward sale obligations, PSEG Power would be required to pay the difference between the market price at the delivery point and the contract price. The amount of such payments could be substantial and could have a material adverse effect on our financial condition, results of operations and cash flows.

In addition, as market prices for energy and fuel fluctuate, our forward energy sale and forward fuel purchase contracts could require us to post substantial additional collateral, thus requiring us to obtain additional sources of liquidity during periods when our ability to do so may be limited.

Certain of our generation facilities rely on transmission facilities that we do not own or control and that may be subject to transmission constraints. Transmission facility owners’ inability to maintain adequate transmission capacity could restrict our ability to deliver wholesale electric power to our customers and we may either incur additional costs or forgo revenues. Conversely, improvements to certain transmission systems could also reduce revenues.

We depend on transmission facilities owned and operated by others to deliver the wholesale power we sell from our generation facilities. If transmission is disrupted or if the transmission capacity infrastructure is inadequate, our ability to sell and deliver wholesale power may be adversely impacted. If a region’s power transmission infrastructure is inadequate, our recovery of wholesale costs and profits may be limited. If restrictive transmission price regulation is imposed, the transmission companies may not have sufficient incentive to invest in transmission infrastructure. We also cannot predict whether transmission facilities will invest in specific markets to accommodate competitive access to those markets.

In addition, in certain of the markets in which we operate, energy transmission congestion may occur and we may be deemed responsible for congestion costs if we schedule delivery of power between congestion zones during times when congestion occurs between the zones. If we were liable for such congestion costs, our financial results could be adversely affected.

Conversely, a portion of our generation is located in load pockets. Investment in transmission systems to reduce or eliminate these load pockets could negatively impact the value or profitability of our existing generation facilities in these areas.

Inability to successfully develop, obtain regulatory approval for, or construct generation, transmission and distribution projects could adversely impact our businesses.

Our business plan calls for extensive investment in capital improvements and additions, including the installation of required environmental upgrades and retrofits; construction and/or acquisition of additional generation units and T&D facilities; and modernizing existing infrastructure pursuant to investment programs entitled to current recovery. Currently, we have several significant projects underway or being contemplated.

The successful construction and development of these projects will depend, in part, on our ability to:


•	obtain necessary governmental and regulatory approvals;

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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.

Any delays, cost escalations or otherwise unsuccessful construction and development could materially affect our financial position, results of operations and cash flows. Modifications to existing facilities may require us to install the best available control technology or to achieve the lowest achievable emission rates required by then-current regulations, which would likely result in substantial additional capital expenditures.

In addition, the successful operation of new or upgraded generation facilities or transmission or distribution projects is subject to risks relating to supply interruptions; work stoppages and labor disputes; weather interferences; unforeseen engineering and environmental problems, including those related to climate change; and the other risks described herein. Any of these risks could cause our return on these investments to be lower than expected or they could cause these facilities to operate below expected capacity or availability levels, which would adversely impact our financial condition and results of operations through lost revenue, increased expenses, higher maintenance costs and penalties.

FERC Order 1000 has generally opened transmission development to competition from independent developers, allowing such developers to compete with incumbent utilities for the construction and operation of transmission facilities in its service territory. While Order 1000 retains limited carve-outs for certain projects that will continue to default to incumbents for construction responsibility, including immediately needed reliability projects, upgrades to existing transmission facilities, projects cost-allocated to a single transmission zone, and projects being built on existing rights-of-way and whose construction would interfere with incumbents’ use of their rights-of-way, increased competition for transmission projects could decrease the value of new investments that would be subject to recovery by PSE&G under its rate base, which could have a material adverse impact on our financial condition and results of operations.

In June 2019, the BPU selected Ørsted US Offshore Wind’s Ocean Wind project as the winning bid in New Jersey’s initial 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. If PSEG elects to acquire an equity interest, PSEG would be required to incur additional capital expenditures. The amount of such capital expenditures, if any, cannot be determined at this time.

We may be adversely affected by equipment failures, accidents, severe weather events or other incidents that impact our ability to provide safe and reliable service to our customers and remain competitive and could result in substantial financial losses.

The success of our businesses is dependent on our ability to continue providing safe and reliable service to our customers while minimizing service disruptions. We are exposed to the risk of equipment failures, accidents, severe weather events, or other incidents which could result in damage to or destruction of our facilities or damage to persons or property. For instance, equipment failures in our natural gas distribution system could give rise to a variety of hazards and operating risks, such as leaks, accidental explosions and mechanical problems, which could cause substantial financial losses and harm our reputation.

In addition, the physical risks of severe weather events, such as experienced from Hurricane Irene and Superstorm Sandy, and of climate change, changes in sea level, temperature and precipitation patterns and other related phenomena have further exacerbated these risks. Such issues experienced at our facilities, or by others in our industry, could adversely impact our revenues; increase costs to repair and maintain our systems; subject us to potential litigation and/or damage claims, fines or penalties; and increase the level of oversight of our utility and generation operations and infrastructure through investigations or through the imposition of additional regulatory or legislative requirements. Such actions could adversely affect our costs, competitiveness and future investments, which could be material to our financial position, results of operations and cash flow. For our T&D business, the cost of storm restoration efforts may not be fully recoverable through the regulatory process. In addition, the inability to restore power to our customers on a timely basis could also materially damage our reputation.

We own less than a controlling interest in some of our generating facilities.

We have limited control over the operation of some of our generating facilities because our investments represent less than a controlling interest. We seek to exert a degree of influence with respect to the management and operation of projects in which we own less than a controlling interest by negotiating to obtain positions on management committees or to receive certain

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limited governance rights. However, we may not always succeed in such negotiations. As a result, we may be dependent on our partners to operate such facilities. The approval of our partners also may be required for us to transfer our interest in such projects. Reliance on our partners for the management and operation of these facilities could result in a lower return on these facilities than what we believe we could have otherwise achieved.

Any inability to recover the carrying amount of our long-lived assets and leveraged leases could result in future impairment charges which could have a material adverse impact on our financial condition and results of operations.

Long-lived assets represent approximately 75%, 82% and 66% of the total assets of PSEG, PSE&G and PSEG Power, respectively, as of December 31, 2019. Management evaluates long-lived assets for impairment whenever events or changes in circumstances, such as significant adverse changes in regulation, business climate or market conditions, including prolonged periods of adverse commodity and capacity prices, could potentially indicate an asset’s or group of assets’ carrying amount may not be recoverable. Significant reductions in our expected revenues or cash flows for an extended period of time resulting from such events could result in future asset impairment charges, which could have a material adverse impact on our financial condition and results of operations.

Energy Holdings has investments in domestic energy and real estate assets subject primarily to leveraged lease accounting. A leveraged lease is typically comprised of an investment by an equity investor and debt provided by a third-party debt investor. As an equity investor, Energy Holdings’ equity investments in the leases are comprised of the total expected lease receivables over the lease terms plus the estimated residual values at the end of the lease terms, reduced for any income not yet earned on the leases. Our receipt of payments related to our leveraged lease portfolio in accordance with the lease contracts can be impacted by various factors, including new environmental legislation regarding air quality and other discharges in the process of generating electricity; market prices for fuel and electricity; overall financial condition of lease counterparties; and the quality and condition of assets under lease.

There can be no assurance that a continuation or worsening of the adverse economic conditions would not lead to additional write-downs at any of our assets in our leveraged lease portfolio, and such write-downs could be material.

Inability to maintain sufficient liquidity in the amounts and at the times needed or access sufficient capital at reasonable rates or on commercially reasonable terms could adversely impact our business.

Funding for our investments in capital improvement and additions, scheduled payments of principal and interest on our existing indebtedness and the extension and refinancing of such indebtedness has been provided primarily by internally-generated cash flow and external financings. We have significant capital requirements and depend on our ability to generate cash in the future from our operations and continued access to capital and credit markets to efficiently fund our cash flow needs. Our ability to generate cash flow is dependent upon, among other things, industry conditions and general economic, financial, competitive, legislative, regulatory and other factors. The ability to arrange financing and the costs of such financing depend on numerous factors including, among other things.


•	general economic and capital market conditions;


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


•	tax, regulatory and securities law developments;


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


•	investor confidence in us and our industry;


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


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


•	our current and future capital structure;


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


•	maintenance of our investment grade credit ratings.

Market disruptions, such as economic downturns experienced in the U.S. and abroad, the bankruptcy of an unrelated energy company or a systemically important financial institution, changes in market prices for electricity and gas, and actual or threatened acts of war or terrorist attacks, may increase our cost of borrowing or adversely affect our ability to access capital. As a result, no assurance can be given that we will be successful in obtaining financing for projects and investments, to extend or refinance maturing debt or for our other cash flow needs on acceptable terms or at all, which could materially adversely impact our financial position, results of operations and future growth.

In addition, if PSEG Power were to lose its investment grade credit rating from S&P or Moody’s, it would be required under certain agreements to provide a significant amount of additional collateral in the form of letters of credit or cash, which would have a material adverse effect on our liquidity and cash flows.

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We may be unable to realize anticipated tax benefits or retain existing tax credits.

The deferred tax assets and tax credits of PSEG, PSE&G or PSEG Power are evaluated for ultimate ability to realize these assets. A valuation allowance may be recorded against the deferred tax assets if we estimate that such assets are more likely than not to be unrealizable based on available evidence including cumulative and forecasted pre-tax book earnings at the time the estimate is made. A valuation allowance related to deferred tax assets or the monetization of tax credits can be affected by changes to tax laws, statutory tax rates and future taxable income levels. In the event that we determine that we would not be able to realize all or a portion of our deferred tax assets in the future or the benefit of tax credits, we would reduce such amounts through a charge to income tax expense in the period in which that determination was made, which could have a material adverse impact on our financial condition and results of operations.

Challenges associated with recruitment and/or retention of key executives and a skilled workforce could adversely impact our businesses.

Our operations depend on the recruitment and retention of key executives and a skilled workforce. The loss or retirement of key executives or other employees, including those with the specialized knowledge required to support our generation and T&D operations, could result in various operational challenges. Certain events, such as the potential for early retirement of our nuclear facilities, can make it more difficult to retain these employees. We may incur increased costs for contractors to replace employees, and the loss of institutional and industry knowledge and the increased costs to hire and lengthy time to train new personnel could result in lower productivity, resulting in increased costs, which would negatively impact our results of operations. This has the potential to become more critical as a growing number of employees become eligible to retire.

As of December 31, 2019, approximately 62% of our employees were covered by collective bargaining agreements. As a result, our success will depend on our ability to successfully renegotiate these agreements as they expire. Inability to do so may result in employee strikes or work stoppages which would disrupt our operations and could also result in increased costs, all of which could have a material adverse effect on our business, financial condition, results of operations and cash flows.

Covenants in our debt instruments may adversely affect our operations.

PSEG’s, PSE&G’s and PSEG Power’s debt instruments contain events of default customary for financings of their type, including cross accelerations to other debt of that entity and, in the case of PSEG’s and PSEG Power’s bank credit agreements, certain change of control events. PSEG Power’s bank credit agreements and outstanding notes also contain limitations on the incurrence of subsidiary debt and liens and certain of PSEG Power’s outstanding notes require PSEG Power to repurchase such notes upon certain change of control events. Our ability to comply with these covenants may be affected by events beyond our control. If we fail to comply with the covenants and are unable to obtain a waiver or amendment, or a default exists and is continuing under such debt, the lenders or the holders or trustee of such debt, as applicable, could give notice and declare outstanding borrowings and other obligations under such debt immediately due and payable. We may not be able to obtain waivers, amendments or alternative financing, or if obtainable, it could be on terms that are not acceptable to us. Any of these events could adversely impact our financial condition, results of operations and cash flows.

Cybersecurity attacks or intrusions could adversely impact our businesses.

Cybersecurity threats to the U.S. energy market infrastructure are increasing in sophistication, magnitude and frequency. We rely on information technology systems that utilize sophisticated digital systems and network infrastructure to operate our generation and T&D systems. We also store sensitive data, intellectual property and proprietary or personally identifiable information regarding our business, employees, shareholders, customers and vendors on our systems and conduct power marketing and hedging activities. In addition, the operation of our business is dependent upon the information technology systems of third parties, including our vendors, regulators, RTOs and ISOs, among others. Our and third-party information technology systems may be vulnerable to cybersecurity attacks involving fraud or malice on the part of our employees, other insiders or third parties, whether domestic or foreign sources. A cybersecurity attack may also leverage such information technology to cause disruptions at a third party. Cybersecurity impacts to our operations include:


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


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


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


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

We and our third-party vendors have been and likely will continue to be subject to attempted cybersecurity attacks. While there has been no material impact on our business or operations from these attempted attacks, if a significant cybersecurity event or breach should occur within our company or with one of our material vendors, we could be exposed to significant loss of revenue, material repair costs to intellectual and physical property, significant fines and penalties for non-compliance with

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existing laws and regulations, significant litigation costs, increased costs to finance our businesses, damage to our reputation and loss of confidence from our customers, regulators, investors, vendors and employees. Similarly, a significant cybersecurity event or breach experienced by a competitor, regulatory authority, RTO, ISO, or vendor could also materially impact our business and results of operations via enhanced legal and regulatory requirements. For a discussion of state and federal cybersecurity regulatory requirements and information regarding our cybersecurity program, see Item 1. Business—Regulatory Issues.

The market for cybersecurity insurance is relatively new and coverage available for cybersecurity events is expected to evolve as the industry matures. While we maintain insurance relating to cybersecurity events, such insurance is subject to a number of exclusions and may be insufficient to offset any losses, costs or damage we experience.

Acts of war or terrorism could adversely affect our operations.

Our businesses and industry may be impacted by acts and threats of war or terrorism. These actions could result in increased political, economic and financial and insurance market instability and volatility in power and fuel markets, which could materially adversely affect our business and results of operations, including our ability to access capital on terms and conditions acceptable to us. In addition, our infrastructure facilities, such as our generating stations, T&D facilities and information technology systems, could be direct or indirect targets or be affected by acts of war or terrorist or other criminal activity. Such events could severely disrupt our business operations and prevent us from servicing our customers. New or updated security regulations may require us to make changes to our current measures which could also result in additional expenses.

ITEM 1B. UNRESOLVED STAFF COMMENTS

PSEG, PSE&G and PSEG Power

None.

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ITEM 2. PROPERTIES

Our subsidiaries own all of our physical property. We believe that we and our subsidiaries maintain adequate insurance coverage against loss or damage to plants and properties, subject to certain exceptions, to the extent such property is usually insured and insurance is available at a reasonable cost. For a discussion of nuclear insurance, see Item 8. Note 15. Commitments and Contingent Liabilities.

Generation Facilities

PSEG Power

As of December 31, 2019, PSEG Power’s share of installed fossil and nuclear generating capacity is shown in the following

table:




Name	Location	Total Capacity (MW)	% Owned	Owned Capacity (MW)	Principal Fuels Used
Steam:
Bridgeport Harbor (A)	CT	383	100%	383	Coal
New Haven Harbor	CT	448	100%	448	Oil/Gas
Total Steam		831		831
Nuclear:
Hope Creek	NJ	1,173	100%	1,173	Nuclear
Salem 1 & 2	NJ	2,285	57%	1,311	Nuclear
Peach Bottom 2 & 3 (B)	PA	2,549	50%	1,275	Nuclear
Total Nuclear		6,007		3,759
Combined Cycle:
Keys	MD	761	100%	761	Gas
Bergen	NJ	1,229	100%	1,229	Gas/Oil
Linden	NJ	1,300	100%	1,300	Gas/Oil
Sewaren 7	NJ	538	100%	538	Gas/Oil
Bridgeport Harbor 5 (C)	CT	484	100%	484	Gas
Bethlehem	NY	815	100%	815	Gas
Kalaeloa	HI	208	50%	104	Oil
Total Combined Cycle		5,335		5,231
Combustion Turbine:
Essex	NJ	81	100%	81	Gas/Oil
Kearny	NJ	456	100%	456	Gas/Oil
Burlington	NJ	168	100%	168	Gas/Oil
Linden	NJ	336	100%	336	Gas/Oil
New Haven Harbor	CT	130	100%	130	Gas/Oil
Bridgeport Harbor	CT	17	100%	17	Oil
Total Combustion Turbine		1,188		1,188
Pumped Storage:
Yards Creek (D)	NJ	420	50%	210
Total PSEG Power Plants		13,781		11,219

(A)Plan to early retire in 2021.

(B)Operated by Exelon Generation.

(C)Commenced commercial operation in June 2019.


(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.

As of December 31, 2019, PSEG Power also owned and operated 467 MW dc of PV solar generation facilities in various states.

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PSE&G

Primarily all of PSE&G’s property is located in New Jersey and PSE&G’s First and Refunding Mortgage, which secures the bonds issued thereunder, constitutes a direct first mortgage lien on substantially all of PSE&G’s property. PSE&G’s electric lines and gas mains are located over or under public highways, streets, alleys or lands, except where they are located over or under property owned by PSE&G or occupied by it under easements or other rights. PSE&G deems these easements and other rights to be adequate for the purposes for which they are being used.

Electric Property and Facilities

As of December 31, 2019, PSE&G’s electric T&D system included approximately 25,000 circuit miles, and 858,000 poles, of which 64% are jointly-owned. In addition, PSE&G owns and operates 52 switching stations with an aggregate installed capacity of 37,353 megavolt-amperes (MVA) and 244 substations with an aggregate installed capacity of 8,428 MVA. Four of those substations, having an aggregate installed capacity of 109 MVA are operated on leased property. In addition, PSE&G owns four electric distribution headquarters and five electric sub-headquarters.

Gas Property and Facilities

As of December 31, 2019, PSE&G’s gas system included approximately 18,000 miles of gas mains, 12 gas distribution headquarters, two sub-headquarters, and one meter shop serving all of its gas territory in New Jersey. In addition, PSE&G operates 58 natural gas metering and regulating stations, of which 22 are located on land owned by customers or natural gas pipeline suppliers and are operated under lease, easement or other similar arrangement. In some instances, the pipeline companies own portions of the metering and regulating facilities. PSE&G also owns one liquefied natural gas and three liquid petroleum air gas peaking facilities. The daily gas capacity of these peaking facilities (the maximum daily gas delivery available during the three peak winter months) is approximately 2.5 million therms in the aggregate.

Solar

As of December 31, 2019, PSE&G had 150 MW dc of installed PV solar capacity throughout New Jersey.

ITEM 3. LEGAL PROCEEDINGS

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

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Our common stock is listed on the New York Stock Exchange, Inc. under the trading symbol “PEG.” As of February 21, 2020, there were 55,987 registered holders.

The following graph shows a comparison of the five-year cumulative return assuming $100 invested on December 31, 2014 in our common stock and the subsequent reinvestment of quarterly dividends, the S&P Composite Stock Price Index, the Dow Jones Utilities Index and the S&P Electric Utilities Index.




	2014		2015		2016		2017		2018		2019
PSEG	$	100.00	$	97.22	$	114.50	$	139.43	$	145.94	$	170.87
S&P 500	$	100.00	$	101.37	$	113.49	$	138.26	$	132.19	$	173.80
DJ Utilities	$	100.00	$	96.93	$	114.55	$	129.85	$	132.43	$	168.57
S&P Electrics	$	100.00	$	95.16	$	110.65	$	124.05	$	129.15	$	163.24

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On February 18, 2020, our Board of Directors approved a $0.49 per share common stock dividend for the first quarter of 2020. This reflects an indicative annual dividend rate of $1.96 per share. We expect to continue to pay cash dividends on our common stock; however, the declaration and payment of future dividends to holders of our common stock will be at the discretion of the Board of Directors and will depend upon many factors, including our financial condition, earnings, capital requirements of our businesses, alternate investment opportunities, legal requirements, regulatory constraints, industry practice and other factors that the Board of Directors deems relevant.

In November 2019, we entered into a share repurchase plan that complies with Rule 10b5-1 of the Securities Exchange Act of 1934, as amended, solely with respect to the repurchase of shares to satisfy obligations under equity compensation awards that are expected to vest in 2020. There were no common share repurchases in the open market during the fourth quarter of 2019.

The following table indicates the securities authorized for issuance under equity compensation plans as of December 31, 2019:




Plan Category	Number of Securities to be Issued upon Exercise of Outstanding Options, Warrants and Rights	Weighted-Average Exercise Price of Outstanding Options, Warrants and Rights		Number of Securities Remaining Available for Future Issuance under Equity Compensation Plans
Long-Term Incentive Plan	—	$	—	12,492,253
Employee Stock Purchase Plan	—	—		2,608,284
Total	—	$	—	15,100,537

For additional discussion of specific plans concerning equity-based compensation, see Item 8. Note 20. Stock Based Compensation.

PSE&G

We own all of the common stock of PSE&G. For additional information regarding PSE&G’s ability to continue to pay dividends, see Item 7. MD&A—Liquidity and Capital Resources.

PSEG Power

We own all of PSEG Power’s outstanding limited liability company membership interests. For additional information regarding PSEG Power’s ability to pay dividends, see Item 7. MD&A—Liquidity and Capital Resources.

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ITEM 6. SELECTED FINANCIAL DATA

PSEG

The information presented below should be read in conjunction with the MD&A and the Consolidated Financial Statements and Notes to Consolidated Financial Statements.




PSEG
Years Ended December 31,	2019		2018		2017		2016		2015
	Millions, except Earnings per Share
Operating Revenues (A)	$	10,076	$	9,696	$	9,094	$	8,966	$	10,415
Income from Continuing Operations (B)(C)(D)(E)	$	1,693	$	1,438	$	1,574	$	887	$	1,679
Net Income (B)(C)(D)(E)	$	1,693	$	1,438	$	1,574	$	887	$	1,679
Earnings per Share:
Income from Continuing Operations
Basic	$	3.35	$	2.85	$	3.12	$	1.76	$	3.32
Diluted	$	3.33	$	2.83	$	3.10	$	1.75	$	3.30
Net Income
Basic	$	3.35	$	2.85	$	3.12	$	1.76	$	3.32
Diluted	$	3.33	$	2.83	$	3.10	$	1.75	$	3.30
Dividends Declared per Share	$	1.88	$	1.80	$	1.72	$	1.64	$	1.56
As of December 31,
Total Assets	$	47,730	$	45,326	$	42,716	$	40,070	$	37,535
Long-Term Obligations	$	13,743	$	13,168	$	12,071	$	10,897	$	8,837


(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.

PSE&G and PSEG Power

Omitted pursuant to conditions set forth in General Instruction I of Form 10-K.

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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (MD&A)

This combined MD&A is separately filed by Public Service Enterprise Group Incorporated (PSEG), Public Service Electric and Gas Company (PSE&G) and PSEG Power LLC (PSEG Power). Information contained herein relating to any individual company is filed by such company on its own behalf. PSE&G and PSEG Power each make representations only as to itself and make no representations whatsoever as to any other company.

PSEG’s business consists of two reportable segments, our principal direct wholly owned subsidiaries, which are:

•

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

•

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

PSEG’s other direct wholly owned subsidiaries are: PSEG Long Island LLC (PSEG LI), which operates the Long Island Power Authority’s (LIPA) transmission and distribution (T&D) system under an Operations Services Agreement; PSEG Energy Holdings L.L.C. (Energy Holdings), which primarily has investments in leveraged leases; and PSEG Services Corporation (Services), which provides certain management, administrative and general services to PSEG and its subsidiaries at cost.

Our business discussion in Item 1. Business provides a review of the regions and markets where we operate and compete, as well as our strategy for conducting our businesses within these markets, focusing on operational excellence, financial strength and making disciplined investments. Our risk factor discussion in Item 1A. Risk Factors provides information about factors that could have a material adverse impact on our businesses. The following discussion provides an overview of the significant events and business developments that have occurred during 2019 and key factors that we expect may drive our future performance. This discussion refers to the Consolidated Financial Statements (Statements) and the related Notes to the Consolidated Financial Statements (Notes). This discussion should be read in conjunction with such Statements and Notes.

For a discussion of 2017 items and year-over-year comparisons of changes in our financial condition and results of operations as of and for the years ended December 31, 2018 and December 31, 2017, see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations in our Annual Report on Form 10-K for the year ended December 31, 2018 (2018 Annual Report) as filed with the Securities and Exchange Commission on February 27, 2019.

EXECUTIVE OVERVIEW OF 2019 AND FUTURE OUTLOOK

Our business plan is designed to achieve growth while managing the risks associated with regulatory changes, fluctuating commodity prices and changes in customer demand. Over the past few years, our investments have altered our business mix to reflect a higher percentage of earnings contribution by PSE&G.

PSE&G

At PSE&G, our focus is on enhancing reliability and resiliency of our T&D system, meeting customer expectations and supporting public policy objectives by investing capital in T&D infrastructure and clean energy programs. For the five-year period ending December 31, 2024, PSE&G expects to invest between $11.5 billion to $15 billion, resulting in an expected compound annual rate base growth of 6.5% to 8%. These ranges are driven by certain unapproved investment programs, including the Clean Energy Future (CEF) and incremental reliability and resiliency investments anticipated in the 2024 timeframe that we intend to seek approval for under the third phase of existing infrastructure programs. See below for a description of the CEF program.

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. Approximately $1.6 billion will be recovered through periodic rate roll-ins, with the remaining $300 million to be recovered through a future base rate proceeding. As part of the settlement approved by the BPU,

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PSE&G agreed to file a base rate proceeding no later than December 2023, to maintain a base level of gas distribution capital expenditures of $155 million per year and to achieve certain leak reduction targets.

Also in 2019, the BPU approved our Energy Strong II Program, an $842 million program to harden, modernize and improve the resiliency of our electric and gas distribution systems. This program began in the fourth quarter of 2019 and is expected to be completed by the end of 2023. Approximately $692 million of the program will be recovered through periodic rate recovery filings, with the balance to be recovered in our next distribution base rate case, which is required to be filed no later than December 2023.

In October 2018, we filed our proposed CEF program with the BPU, a six-year estimated $3.5 billion investment covering four programs; (i) an Energy Efficiency (EE) program totaling $2.5 billion of investment designed to achieve energy efficiency targets required 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, the State 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.

We also continue to invest in transmission infrastructure in order to (i) maintain and enhance system integrity and grid reliability, grid security and safety, (ii) address an aging transmission infrastructure, (iii) leverage technology to improve the operation of the system, (iv) reduce transmission constraints, (v) meet growing demand and (vi) meet environmental requirements and standards set by various regulatory bodies. Our planned capital spending for transmission in 2020-2022 is $2.8 billion.

PSEG Power

At PSEG Power, we strive to improve performance and reduce costs in order to optimize cash flow generation from our fleet in light of low wholesale power and gas prices, environmental considerations and competitive market forces that reward efficiency and reliability. PSEG Power continues to move its fleet toward improved efficiency and believes that its recently completed investment program enhances its competitive position with the addition of efficient, clean, reliable combined cycle gas turbine capacity. In 2019, our natural gas fleet generated 23 terawatt hours and our nuclear fleet achieved a capacity factor of 88.7%. Our commitments for load, such as basic generation service (BGS) in New Jersey and other bilateral supply contracts, are backed by this generation or may be combined with the use of physical commodity purchases and financial instruments from the market to optimize the economic efficiency of serving our obligations. PSEG Power’s hedging practices and ability to capitalize on market opportunities help it to balance some of the volatility of the merchant power business. More than 70% of PSEG Power’s expected gross margin in 2020 relates to hedging of our energy margin, our expected revenues from the capacity market mechanisms, Zero Emission Certificate (ZEC) revenues that commenced in April 2019 and certain ancillary service payments such as reactive power.

PSEG Power completed its 1,800 MW combined cycle gas turbine construction program with the addition of the Keys Energy Center (Keys) in Maryland and Sewaren 7 in New Jersey in 2018 and Bridgeport Harbor Station Unit 5 (BH5) in Connecticut in 2019. These additions to our fleet both expand our geographic diversity and adjust our fuel mix and enhance the environmental profile and overall efficiency of PSEG Power’s generation fleet.

Operational Excellence

We emphasize operational performance while developing opportunities in both our competitive and regulated businesses. Flexibility in our generating fleet has allowed us to take advantage of opportunities in a rapidly evolving market as we remain diligent in managing costs. In 2019, our


•	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 18^th 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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Financial Strength

Our financial strength is predicated on a solid balance sheet, positive operating cash flow and reasonable risk-adjusted returns on increased investment. Our financial position remained strong during 2019 as we


•	maintained sufficient liquidity,


•	maintained solid investment grade credit ratings, and


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

We expect to be able to fund our planned capital requirements, as described in Liquidity and Capital Resources, and the impacts of the Tax Cuts and Jobs Act of 2017 (Tax Act) without the issuance of new equity. For additional information on the impacts of the Tax Act, see Item 8. Note 7. Regulatory Assets and Liabilities and Note 22. Income Taxes.

Financial Results

As a result of the settlement of PSE&G’s distribution base rate proceeding in 2018, PSE&G’s overall 2019 annual revenues were reduced by 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 in 2019 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 flowback of accumulated deferred income taxes from previously realized tax repair deductions and tax benefits from future tax repair deductions as realized.

PSE&G also filed a revised 2019 Transmission Formula Rate Annual Update to include the refund of the approved excess deferred income tax benefits. The revised 2019 Annual Transmission Formula Rate, as filed with FERC in January 2019, decreased overall annual transmission revenues by approximately $54 million, and was offset by estimated true-up adjustments, resulting in a net decrease in 2019 transmission revenues of $19 million. PSE&G will file a final true-up to the 2019 Annual Transmission Formula Rate Update in the second quarter of 2020.

The financial results for PSEG, PSE&G and PSEG Power for the years ended December 31, 2019 and 2018 are presented as follows:




	Years Ended December 31,
	2019			2018
	Millions, except per share data
PSE&G	$	1,250		$	1,067
PSEG Power	468			365
Other	(25		)	6
PSEG Net Income	$	1,693		$	1,438

PSEG Net Income Per Share (Diluted)	$	3.33		$	2.83

Our 2019 over 2018 increase in Net Income was due primarily to higher earnings from distribution rate relief and transmission and distribution investments at PSE&G, MTM and Nuclear Decommissioning Trust (NDT) Fund gains in 2019 as compared to losses in the prior year and ZEC revenues in 2019 at PSEG Power, and pension credits resulting from retiree medical plan benefit changes in 2019. These increases were partially offset by a loss on the sale in 2019 of PSEG Power’s ownership interests in two fossil plants. For a more detailed discussion of our financial results, see Results of Operations.

The greater emphasis on capital spending in recent years for projects on which we receive contemporaneous returns at PSE&G has yielded strong results, which when combined with the cash flow generated by PSEG Power, has allowed us to meet customer needs, address market conditions and investor expectations, reflecting our long-term approach to managing our company. We continue our focus on operational excellence, financial strength and disciplined investment. These guiding principles have provided the base from which we have been able to execute our strategic initiatives.

Disciplined Investment

We utilize rigorous criteria when deploying capital and seek to invest in areas that complement our existing business and provide reasonable risk-adjusted returns. These areas include upgrading our energy infrastructure and improving our environmental footprint to align with public policy objectives. In 2019, we


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


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

Regulatory, Legislative and Other Developments

In our pursuit of operational excellence, financial strength and disciplined investment, we closely monitor and engage with stakeholders on significant regulatory and legislative developments. Transmission planning rules and wholesale power market design are of particular importance to our results and we continue to advocate for policies and rules that promote fair and efficient electricity markets. For additional information about regulatory, legislative and other developments that may affect the company, see Item 1. Business—Regulatory Issues.

Transmission Planning

In March 2019, FERC issued a Notice of Inquiry (NOI) seeking comment on improvements to FERC’s electric transmission incentives policy to ensure that it appropriately encourages the development of the infrastructure needed to ensure grid reliability and reduce congestion to lower the cost of power for consumers. The NOI is intended to examine whether existing incentives, such as the 50 basis point adder for membership in the Regional Transmission Organization, should continue to be granted and whether new incentives should be established.

In November 2019, FERC issued an order establishing a new Return on Equity (ROE) policy for reviewing existing transmission ROEs. FERC applied the methodology outlined in the new policy to two complaints filed against the Midcontinent Independent System Operator (MISO) transmission owners and found that the MISO transmission owners’ ROE was unjust and unreasonable and directed that the ROE be lowered. 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.

Wholesale Power Market Design

In January 2020, New Jersey rejoined the Regional Greenhouse Gas Initiative (RGGI). As a result, generating plants operating in New Jersey, including those owned by PSEG Power, that emit carbon dioxide (CO₂) emissions will be required to procure credits for each ton they emit. In response to RGGI, PJM initiated a process in 2019 to investigate the development of a carbon pricing mechanism that may mitigate the environmental and financial distortions that could occur when emissions “leak” from non-participating states to the RGGI states. If the process leads to a market solution, it could have a material impact on the value of PSEG Power’s generating fleet.

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. Subsidized units that cannot clear in a Reliability Pricing Model (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 the 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 a 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 addition, we cannot predict whether there will be challenges to the FERC order and, if so, the impact of such challenges on the MOPR and other capacity market rules.

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Environmental Regulation

We are subject to liability under environmental laws for the costs of remediating environmental contamination of property now or formerly owned by us and of property contaminated by hazardous substances that we generated. In particular, the historic operations of PSEG companies and the operations of numerous other companies along the Passaic and Hackensack Rivers are alleged by Federal and State agencies to have discharged substantial contamination into the Passaic River/Newark Bay Complex in violation of various statutes. We are also currently involved in a number of proceedings relating to sites where other hazardous substances may have been discharged and may be subject to additional proceedings in the future, and the costs of any such remediation efforts could be material.

For further information regarding the matters described above, as well as other matters that may impact our financial condition and results of operations, see Item 8. Note 15. Commitments and Contingent Liabilities.

Nuclear

In April 2019, PSEG Power’s Salem 1, Salem 2 and Hope Creek nuclear plants were awarded ZECs by the BPU. Pursuant to a process established by the BPU, ZECs are purchased from selected nuclear plants and recovered through a non-bypassable distribution charge in the amount of $0.004 per kilowatt-hour used (which is equivalent to approximately $10 per megawatt hour generated in payments to selected nuclear plants (ZEC payment)). These nuclear plants are expected to receive ZEC revenue for approximately three years, through May 2022, and will be obligated to maintain operations during that period, subject to exceptions specified in the ZEC legislation. PSEG Power has and will continue to recognize revenue monthly as the nuclear plants generate electricity and satisfy their performance obligations. The ZEC legislation requires nuclear plants to reapply for any subsequent three year periods. The ZEC payment may be adjusted by the BPU (a) at any time to offset environmental or fuel diversity payments that a selected nuclear plant may receive from another source or (b) at certain times specified in the ZEC legislation if the BPU determines that the purposes of the ZEC legislation can be achieved through a reduced charge that will nonetheless be sufficient to achieve the state’s air quality and other environmental objectives by preventing the retirement of nuclear plants. The BPU’s decision awarding ZECs has been appealed by the Division of Rate Counsel. PSEG cannot predict the outcome of this matter. In the event that (i) the ZEC program is overturned or otherwise materially adversely modified through legal process, (ii) the terms and conditions of the subsequent period under the ZEC program, including the amount of ZEC payments that may be awarded, materially differ from those of the current ZEC period, or (iii) any of the Salem 1, Salem 2 and Hope Creek plants is not awarded ZEC payments by the BPU and does not otherwise experience a material financial change, PSEG Power will take all necessary steps to retire all of these plants subsequent to the initial ZEC period at or prior to a scheduled refueling outage. Alternatively, if all of the Salem 1, Salem 2 and Hope Creek plants are selected to continue to receive ZEC payments but the financial condition of the plants is materially adversely impacted by changes in commodity prices, FERC’s changes to the capacity market construct (absent sufficient capacity revenues provided under a program approved by the BPU in accordance with a FERC-authorized capacity mechanism), or, in the case of the Salem nuclear plants, decisions by the EPA and state environmental regulators regarding the implementation of Section 316(b) of the Clean Water Act and related state regulations, or other factors, PSEG Power would still take all necessary steps to retire all of these plants. Retirement of these plants would result in a material adverse impact on PSEG’s and PSEG Power’s financial results.

Fossil

In September 2019, PSEG Power completed the sale of its ownership interests in the Keystone and Conemaugh generation plants and related assets and liabilities. PSEG Power recorded a pre-tax loss on disposition of approximately $400 million in the second quarter of 2019 as the sale price was less than book value. 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.

California Solar Facilities

As part of its solar production portfolio, PSEG Power owns and operates two California-based solar facilities with an aggregate capacity of approximately 30 MW direct current whose output is sold to Pacific Gas and Electric Company (PG&E) under power purchase agreements (PPAs) with twenty year terms. The net book value of these solar facilities was approximately $55 million as of December 31, 2019. In January 2019, PG&E and its parent company PG&E Corporation filed for Chapter 11 bankruptcy protection. PSEG Power cannot predict the ultimate outcome that this bankruptcy proceeding will have on our ability to collect all of the revenues from these facilities due under the PPAs; however, any adverse changes to the terms of PSEG Power’s PPAs as a result of this bankruptcy proceeding could result in the future impairment of these assets in amounts up to their current net book value.

Offshore Wind

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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.

Leveraged Leases

In December 2018, NRG REMA, LLC emerged from its in-court proceeding under Chapter 11 of the Bankruptcy Code. As a result of the restructuring, the remaining deferred tax liabilities related to the Keystone and Conemaugh lease investments were reclassified to current tax liabilities. PSEG realized the remaining tax liability related to the restructuring of approximately $85 million with the filing of the consolidated federal income tax return in December 2019.

Additional facilities in our leveraged lease portfolio include the Shawville, Joliet and Powerton generating facilities. Converted natural gas units such as Shawville and Joliet may have higher operating costs and fuel consumption, as well as longer start-up times, compared to newer combined cycle gas units. Powerton is a coal-fired generating facility in Illinois.

During the second quarter of 2019, Energy Holdings completed its annual review of estimated residual values embedded in the leveraged leases. The outcome indicated that the updated residual value estimate of the coal-fired Powerton lease was lower than the recorded residual value and the decline was deemed to be other than temporary as a result of expected future adverse market conditions. As a result, a pre-tax write-down of $58 million was reflected in Operating Revenues in the quarter ended June 30, 2019, calculated by comparing the gross investment in the leases before and after the revised residual estimates.

Each of these three facilities may not be as economically competitive as newer combined cycle gas units and could continue to be adversely impacted by the same economic conditions experienced by other less efficient natural gas and coal generation facilities, which could require additional write-downs of the residual values of Energy Holdings’ leveraged lease receivables associated with these facilities.

Tax Legislation

For non-regulated businesses, the Tax Act enacted rules that set a cap on the amount of interest that can be deducted in a given year. Any amount that is disallowed can be carried forward indefinitely. For 2018 and 2019, a portion of PSEG’s and PSEG Power’s interest was disallowed but is expected to be realized in future periods. However, certain aspects of the law are unclear. Therefore, we recorded taxes in 2018 and 2019 based on our interpretation of the relevant statute. Amounts recorded under the Tax Act, such as depreciation and interest disallowance, are subject to change based on several factors, including but not limited to, the Internal Revenue Service and state taxing authorities issuing additional guidance and/or further clarification. Any further guidance or clarification could impact PSEG’s, PSE&G’s and PSEG Power’s financial statements. For additional information, see Item 8. Note 22. Income Taxes.

In July 2018, the State of New Jersey made changes to its income tax laws, including imposing a temporary surtax of 2.5% effective January 1, 2018 and 2019 and 1.5% in 2020 and 2021, as well as requiring corporate taxpayers to file in a combined reporting group as defined under New Jersey law starting in 2019. Both provisions include an exemption for public utilities. We believe PSE&G meets the definition of a public utility and, therefore, will not be impacted by the temporary surtax or be included in the combined reporting group. There are certain aspects of the law that are not clear. We anticipate the State of New Jersey will be issuing clarifying guidance regarding combined reporting rules. Any further guidance or clarification could impact PSEG’s and PSEG Power’s financial statements.

Future Outlook

For more than a century, our mission has been to provide universal access to an around-the-clock supply of reliable, affordable power. Building on this mission, we believe in a future where customers universally use less energy, the energy they use is cleaner, and its delivery is more reliable and more resilient. In July 2019, we announced that we expect to cut carbon emissions at PSEG Power’s generation fleet by 80% by 2046, from 2005 levels. We have also announced our vision of attaining net-zero CO₂emissions by 2050, assuming advances in technology, public policy and customer behavior.

Our future success will depend on our ability to continue to maintain strong operational and financial performance in an environment with low gas prices, to capitalize on or otherwise address regulatory and legislative developments that impact our business and to respond to the issues and challenges described below. In order to do this, we must continue to:


•	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.

In addition to the risks described elsewhere in this Form 10-K for 2020 and beyond, the key issues and challenges we expect our business to confront include:


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


•	the continuing 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.

We continually assess a broad range of strategic options to maximize long-term stockholder value. In assessing our options, we consider a wide variety of factors, including the performance and prospects of our businesses; the views of investors, regulators, customers and rating agencies; our existing indebtedness and restrictions it imposes; and tax considerations, among other things. Strategic options available to us include:


•	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.

There can be no assurance, however, that we will successfully develop and execute any of the strategic options noted above, or any additional options we may consider in the future. The execution of any such strategic plan may not have the expected benefits or may have unexpected adverse consequences.

RESULTS OF OPERATIONS




	Years Ended December 31,
	2019			2018		2017
Earnings (Losses)	Millions
PSE&G	$	1,250		$	1,067	$	973
PSEG Power (A)(B)	468			365		479
Other (B)(C)	(25		)	6		122
PSEG Net Income	$	1,693		$	1,438	$	1,574

PSEG Net Income Per Share (Diluted)	$	3.33		$	2.83	$	3.10

(A)

PSEG Power’s results in 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.

PSEG Power’s results above include the NDT Fund activity and the impacts of non-trading commodity mark-to-market (MTM) activity, which consist of the financial impact from positions with future delivery dates.

The variances in our Net Income attributable to changes related to the NDT Fund and MTM are shown in the following table:




Years Ended December 31,	2019		2018			2017
	Millions, after tax
NDT Fund and Related Activity (A) (B)	$	152	$	(90	)	$	62
Non-Trading MTM Gains (Losses) (C)	$	205	$	(84	)	$	(99	)

(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.

Our 2019 $255 million year-over-year increase was driven primarily by


•	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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PSEG

Our results of operations are primarily comprised of the results of operations of our principal operating subsidiaries, PSE&G and PSEG Power, excluding charges related to intercompany transactions, which are eliminated in consolidation. For additional information on intercompany transactions, see Item 8. Note 26. Related-Party Transactions.




									Increase / (Decrease)					Increase / (Decrease)
	Years Ended December 31,								Increase / (Decrease)					Increase / (Decrease)
	2019		2018			2017			2019 vs. 2018					2018 vs. 2017
	Millions								Millions			%		Millions			%
Operating Revenues	$	10,076	$	9,696		$	9,094		$	380		4		$	602		7
Energy Costs	3,372		3,225			2,778			147			5		447			16
Operation and Maintenance	3,111		3,069			2,901			42			1		168			6
Depreciation and Amortization	1,248		1,158			1,986			90			8		(828		)	(42	)
(Gain) Loss on Asset Dispositions	402		(54		)	—			456			N/A		(54		)	N/A
Income from Equity Method Investments	14		15			14			(1		)	(7	)	1			7
Net Gains (Losses) on Trust Investments	260		(143		)	134			403			N/A		(277		)	N/A
Other Income (Deductions)	125		85			82			40			47		3			4
Non-Operating Pension and OPEB Credits (Costs)	177		76			—			101			N/A		76			N/A
Interest Expense	569		476			391			93			20		85			22
Income Tax (Benefit) Expense	257		417			(306		)	(160		)	(38	)	723			N/A

The 2019, 2018 and 2017 amounts in the preceding table for Operating Revenues and O&M costs each include $490 million, $458 million and $438 million, respectively, for PSEG LI’s subsidiary, Long Island Electric Utility Servco, LLC (Servco). These amounts represent the O&M pass-through costs for the Long Island operations, the full reimbursement of which is reflected in Operating Revenues. See Item 8. Note 5. Variable Interest Entity for further explanation. The Income Tax Benefit in 2017 includes the non-cash benefit resulting from the remeasurement of deferred tax liabilities required due to the enactment of the Tax Act in December 2017. The following discussions for PSE&G and PSEG Power provide a detailed explanation of their respective variances.

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PSE&G




	Years Ended December 31,								Increase / (Decrease)					Increase / (Decrease)
	2019		2018			2017			2019 vs. 2018					2018 vs. 2017
	Millions								Millions			%		Millions			%
Operating Revenues	$	6,625	$	6,471		$	6,324		$	154		2		$	147		2
Energy Costs	2,738		2,520			2,421			218			9		99			4
Operation and Maintenance	1,581		1,575			1,458			6			—		117			8
Depreciation and Amortization	837		770			685			67			9		85			12
Net Gains (Losses) on Trust Investments	2		(1		)	2			3			N/A		(3		)	N/A
Other Income (Deductions)	83		80			85			3			4		(5		)	(6	)
Non-Operating Pension and OPEB Credits (Costs)	150		59			(8		)	91			N/A		67			N/A
Interest Expense	361		333			303			28			8		30			10
Income Tax Expense	93		344			563			(251		)	(73	)	(219		)	(39	)

Year Ended December 31, 2019 as compared to 2018

Operating Revenues increased $154 million due to changes in delivery, clause, commodity and other operating revenues.

Delivery Revenues decreased $67 million.


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

•

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.

Clause Revenues decreased $2 million due to $11 million in Tax Adjustment Credits (TAC) and GPRC deferrals. These decreases were partially offset by $6 million in Margin Adjustment Clause (MAC) revenues, $2 million in higher Solar Pilot Recovery Charge (SPRC) collections and higher Societal Benefit Charges (SBC) of $1 million. The changes in TAC and GPRC Deferrals, MAC, SPRC and SBC collections were entirely offset by the amortization of related costs (Regulatory Assets) in O&M, D&A and Interest and Tax Expenses. PSE&G does not earn margin on TAC or GPRC deferrals or on MAC, SPRC or SBC collections.

Commodity Revenues increased $98 million due to higher Gas revenues partially offset by lower Electric revenues. The changes in Commodity Revenues for both gas and electric are entirely offset by changes in Energy Costs. PSE&G earns no margin on the provision of basic gas supply service (BGSS) and BGS to retail customers.


•	Gas revenues increased $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.

Other Operating Revenues increased $125 million due primarily to ZEC revenues billed after the ZEC program was approved by the BPU in April 2019. See Item 8. Note 15. Commitments and Contingent Liabilities. The ZEC revenues are entirely offset by changes to Energy Costs.

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Operating Expenses

Energy Costs increased $218 million. This is entirely offset by changes in Commodity Revenues and Other Operating Revenues.

Operation and Maintenance increased $6 million due primarily to a $42 million net increase for various clause mechanisms and GPRC expenditures and a $4 million increase in injuries and damages. These increases were partially offset by a $19 million decrease in electric distribution maintenance expenditures, a $14 million decrease in transmission maintenance expenditures and a $6 million decrease in storm-related costs.

Depreciation and Amortization increased $67 million due primarily to an increase in depreciation of $52 million due to additional plant placed into service, an $8 million increase due to new depreciation rates resulting from the distribution base rate settlement applied to assets held as of November 1, 2018 and a net $7 million increase from other factors.

Non-Operating Pension and OPEB Credits (Costs) increased $91 million due primarily to a $103 million increase in the amortization of prior service credit mainly related to the December 2018 OPEB plan amendment and a $6 million decrease in interest cost, partially offset by a $17 million reduction in the expected return on plan assets.

Interest Expense increased $28 million due primarily to increases of $18 million due to net long-term debt issuances in 2019 and $12 million due to net long-term debt issuances in 2018.

Income Tax Expense decreased $251 million due primarily to the flowback of excess deferred income tax liabilities and tax repair-related accumulated deferred income taxes to ratepayers.

Year Ended December 31, 2018 as compared to 2017

See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations in our 2018 Annual Report.

PSEG Power




	Years Ended December 31,								Increase / (Decrease)					Increase / (Decrease)
	2019		2018			2017			2019 vs. 2018					2018 vs. 2017
	Millions								Millions			%		Millions			%
Operating Revenues	$	4,385	$	4,146		$	3,860		$	239		6		$	286		7
Energy Costs	2,118		2,197			1,913			(79		)	(4	)	284			15
Operation and Maintenance	1,040		1,053			1,046			(13		)	(1	)	7			1
Depreciation and Amortization	377		354			1,268			23			6		(914		)	(72	)
(Gain) Loss on Asset Dispositions	402		(54		)	—			456			N/A		(54		)	N/A
Income from Equity Method Investments	14		15			14			(1		)	(7	)	1			7
Net Gains (Losses) on Trust Investments	253		(140		)	125			393			N/A		(265		)	N/A
Other Income (Deductions)	54		21			20			33			N/A		1			5
Non-Operating Pension and OPEB Credits (Costs)	21		15			8			6			40		7			88
Interest Expense	119		76			50			43			57		26			52
Income Tax Expense (Benefit)	203		66			(729		)	137			N/A		795			N/A

Year Ended December 31, 2019 as compared to 2018

Operating Revenues increased $239 million due to changes in generation, gas supply and other operating revenues.

Generation Revenues increased $312 million due primarily to


•	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.

Gas Supply Revenues decreased $75 million due primarily to


•	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.

Operating Expenses

Energy Costs represent the cost of generation, which includes fuel costs for generation as well as purchased energy in the market, and gas purchases to meet PSEG Power’s obligation under its BGSS contract with PSE&G. Energy Costs decreased $79 million due to

Gas costs decreased $52 million due primarily to


•	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.

Generation costs decreased $27 million due primarily


•	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,

•

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.

Operation and Maintenance decreased $13 million due primarily to a decrease at our fossil plants, largely due to lower outage costs, decreased support costs and the sale of PSEG Power’s ownership interests in the Keystone and Conemaugh generation plants in September 2019. The decrease was partially offset by a goodwill impairment charge of $16 million for the write down of PSEG Power’s carrying value to fair value (see Note 12. Goodwill and Other Intangibles), increased costs related to the Keys and Sewaren 7 being placed into service in mid-2018 and increased property taxes.

Depreciation and Amortization increased $23 million due primarily to Keys, Sewaren 7 and BH5 being placed into service, partially offset by the sale of PSEG Power’s ownership interests in the Keystone and Conemaugh generation plants.

(Gain) Loss on Asset Dispositions reflects a $402 million loss in 2019 related to the sale of PSEG Power’s ownership interests in the Keystone and Conemaugh generation plants and a gain of $54 million in 2018 related to the sale of the Hudson and Mercer plants.

Net Gains (Losses) on Trust Investments increased $393 million due primarily to a $405 million increase resulting from net unrealized gains in 2019 as compared to net unrealized losses in 2018 on equity investments in the NDT Fund, partially offset by a $16 million decrease in net realized gains on NDT Fund investments.

Other Income (Deductions) increased $33 million primarily due to $26 million in less purchased net operating losses and higher interest and dividend income on NDT Fund investments.

Non-Operating Pension and OPEB Credits (Costs) increased $6 million due to a $19 million increase in the amortization of prior service credit mainly related to the December 2018 OPEB plan amendment, a $5 million decrease in interest cost and a $3

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million decrease in the amortization of the net unrecognized loss, largely offset by a $20 million decrease in the expected return on plan assets.

Interest Expense increased $43 million due primarily to lower capitalized interest as a result of Keys and Sewaren 7 being placed into service in mid-2018 and BH5 being place into service in June 2019.

Income Tax Expense increased $137 million due primarily to higher pre-tax income, including higher pre-tax income from the NDT qualified fund which is subject to an additional trust tax, and the favorable impact that resulted in 2018 from the remeasurement of the reserve for uncertain tax positions.

Year Ended December 31, 2018 as compared to 2017

See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations in our 2018 Annual Report.

LIQUIDITY AND CAPITAL RESOURCES

The following discussion of our liquidity and capital resources is on a consolidated basis, noting the uses and contributions, where material, of our two direct major operating subsidiaries.

Financing Methodology

We expect our capital requirements to be met through internally generated cash flows and external financings, consisting of short-term debt for working capital needs and long-term debt for capital investments.

PSE&G’s sources of external liquidity include a $600 million multi-year revolving credit facility. PSE&G uses internally generated cash flow and its commercial paper program to meet seasonal, intra-month and temporary working capital needs. PSE&G does not engage in any intercompany borrowing or lending arrangements. PSE&G maintains back-up facilities in an amount sufficient to cover the commercial paper and letters of credit outstanding. PSE&G’s dividend payments to/capital contributions from PSEG are consistent with its capital structure objectives which have been established to maintain investment grade credit ratings. PSE&G’s long-term financing plan is designed to replace maturities, fund a portion of its capital program and manage short-term debt balances. Generally, PSE&G uses either secured medium-term notes or first mortgage bonds to raise long-term capital.

PSEG, PSEG Power, Energy Holdings, PSEG LI and Services participate in a corporate money pool, an aggregation of daily cash balances designed to efficiently manage their respective short-term liquidity needs. Servco does not participate in the corporate money pool. Servco’s short-term liquidity needs are met through an account funded and owned by LIPA.

PSEG’s available sources of external liquidity may include the issuance of long-term debt securities and the incurrence of additional indebtedness under credit facilities. Our current sources of external liquidity include multi-year revolving credit facilities totaling $1.5 billion. These facilities are available to back-stop PSEG’s commercial paper program, issue letters of credit and for general corporate purposes. PSEG’s credit facilities and the commercial paper program are available to support PSEG working capital needs or to temporarily fund growth opportunities in advance of obtaining permanent financing. PSEG’s credit facilities are also available to make equity contributions or provide liquidity support to its subsidiaries.

PSEG Power’s sources of external liquidity include $2.1 billion of multi-year revolving credit facilities. Additionally, from time to time, PSEG Power maintains bilateral credit agreements designed to enhance its liquidity position. Credit capacity is primarily used to provide collateral in support of PSEG Power’s forward energy sale and forward fuel purchase contracts as the market prices for energy and fuel fluctuate, and to meet potential collateral postings in the event that PSEG Power is downgraded to below investment grade by Standard & Poor’s (S&P) or Moody’s. PSEG Power’s dividend payments to PSEG are also designed to be consistent with its capital structure objectives which have been established to maintain investment grade credit ratings and provide sufficient financial flexibility. Generally, PSEG Power issues senior unsecured debt to raise long-term capital.

Operating Cash Flows

We expect our operating cash flows combined with cash on hand and financing activities to be sufficient to fund capital expenditures and shareholder dividend payments.

For the year ended December 31, 2019, our operating cash flow increased by $466 million. The net changes were primarily due to net changes from our subsidiaries as discussed below.

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PSE&G

PSE&G’s operating cash flow increased $182 million from $1,853 million to $2,035 million for the year ended December 31, 2019, as compared to 2018, due primarily to an increase of $178 million from recoveries of regulatory deferrals and tax refunds in 2019 as compared to tax payments in 2018, partially offset by $123 million in increased vendor payments.

PSEG Power

PSEG Power’s operating cash flow increased $395 million from $1,084 million to $1,479 million for the year ended December 31, 2019, as compared to 2018, due to a decrease in cash collateral requirements of $596 million, partially offset by an $83 million decrease from net collections of counterparty receivables, and lower tax refunds in 2019 as compared to 2018.

Short-Term Liquidity

PSEG meets its short-term liquidity requirements, as well as those of PSEG Power, primarily with cash and through the issuance of commercial paper. PSE&G maintains its own separate commercial paper program to meet its short-term liquidity requirements. Each commercial paper program is fully back-stopped by its own separate credit facilities.

We continually monitor our liquidity and seek to add capacity as needed to meet our liquidity requirements. Each of our credit facilities is restricted as to availability and use to the specific companies as listed below; however, if necessary, the PSEG facilities can also be used to support our subsidiaries’ liquidity needs.

Our total credit facilities and available liquidity as of December 31, 2019 were as follows:




Company/Facility	As of December 31, 2019
Company/Facility	Total Facility		Usage		Available Liquidity
	Millions
PSEG	$	1,500	$	796	$	704
PSE&G	600		379		221
PSEG Power	2,100		161		1,939
Total	$	4,200	$	1,336	$	2,864

As of December 31, 2019, our credit facility capacity was in excess of our projected maximum liquidity requirements over our 12 month planning horizon. Our maximum liquidity requirements are based on stress scenarios that incorporate changes in commodity prices and the potential impact of PSEG Power losing its investment grade credit rating from S&P or Moody’s, which would represent a three level downgrade from its current S&P or Moody’s ratings. In the event of a deterioration of PSEG Power’s credit rating, certain of PSEG Power’s agreements allow the counterparty to demand further performance assurance. The potential additional collateral that we would be required to post under these agreements if PSEG Power were to lose its investment grade credit rating was approximately $974 million and $857 million as of December 31, 2019 and 2018, respectively.

For additional information, see Item 8. Note 16. Debt and Credit Facilities.

Long-Term Debt Financing

During the next twelve months,


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


•	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.

For a discussion of our long-term debt transactions during 2019, see Item 8. Note 16. Debt and Credit Facilities.

Debt Covenants

Our credit agreements contain maximum debt to equity ratios and other restrictive covenants and conditions to borrowing. We are currently in compliance with all of our debt covenants. Continued compliance with applicable financial covenants will depend upon our future financial position, level of earnings and cash flows, as to which no assurances can be given.

In addition, under its First and Refunding Mortgage (Mortgage), PSE&G may issue new First and Refunding Mortgage Bonds against previous additions and improvements, provided that its ratio of earnings to fixed charges calculated in accordance with

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its Mortgage is at least 2 to 1, and/or against retired Mortgage Bonds. As of December 31, 2019, PSE&G’s Mortgage coverage ratio was 4.5 to 1 and the Mortgage would permit up to approximately $7.6 billion aggregate principal amount of new Mortgage Bonds to be issued against additions and improvements to its property.

Default Provisions

Our bank credit agreements and indentures contain various, customary default provisions that could result in the potential acceleration of indebtedness under the defaulting company’s agreement.

In particular, PSEG’s bank credit agreements contain provisions under which certain events, including an acceleration of material indebtedness under PSE&G’s and PSEG Power’s respective financing agreements, a failure by PSE&G or PSEG Power to satisfy certain final judgments and certain bankruptcy events by PSE&G or PSEG Power, that would constitute an event of default under the PSEG bank credit agreements. Under the PSEG bank credit agreements, it would also be an event of default if either PSE&G or PSEG Power ceases to be wholly owned by PSEG. The PSE&G and PSEG Power bank credit agreements include similar default provisions; however, such provisions only relate to the respective borrower under such agreement and its subsidiaries and do not contain cross default provisions to each other. The PSE&G and PSEG Power bank credit agreements do not include cross default provisions relating to PSEG. PSEG Power’s bank credit agreements and outstanding notes also contain limitations on the incurrence of subsidiary debt and liens and certain of PSEG Power’s outstanding notes require PSEG Power to repurchase such notes upon certain change of control events.

There are no cross-acceleration provisions in PSEG’s or PSE&G’s indentures. However, PSEG’s existing notes include a cross acceleration provision that may be triggered upon the acceleration of more than $75 million of indebtedness incurred by PSEG. Such provision does not extend to an acceleration of indebtedness by any of PSEG’s subsidiaries. PSEG Power’s indenture includes a cross acceleration provision similar to that described above for PSEG’s existing notes except that such provision may be triggered upon the acceleration of more than $50 million of indebtedness incurred by PSEG Power or any of its subsidiaries. Such provision does not cross accelerate to PSEG, any of PSEG’s subsidiaries (other than PSEG Power and its subsidiaries), PSE&G or any of PSE&G’s subsidiaries.

Ratings Triggers

Our debt indentures and credit agreements do not contain any material “ratings triggers” that would cause an acceleration of the required interest and principal payments in the event of a ratings downgrade. However, in the event of a downgrade, any one or more of the affected companies may be subject to increased interest costs on certain bank debt and certain collateral requirements. In the event that we are not able to affirm representations and warranties on credit agreements, lenders would not be required to make loans.

In accordance with BPU requirements under the BGS contracts, PSE&G is required to maintain an investment grade credit rating. If PSE&G were to lose its investment grade rating, it would be required to file a plan to assure continued payment for the BGS requirements of its customers.

Fluctuations in commodity prices or a deterioration of PSEG Power’s credit rating to below investment grade could increase PSEG Power’s required margin postings under various agreements entered into in the normal course of business. PSEG Power believes it has sufficient liquidity to meet the required posting of collateral which would likely result from a credit rating downgrade to below investment grade by S&P or Moody’s at today’s market prices.

Common Stock Dividends




	Years Ended December 31,
Dividend Payments on Common Stock	2019		2018		2017
Per Share	$	1.88	$	1.80	$	1.72
in Millions	$	950	$	910	$	870

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Credit Ratings

If the rating agencies lower or withdraw our credit ratings, such revisions may adversely affect the market price of our securities and serve to materially increase our cost of capital and limit access to capital. Credit Ratings shown are for securities that we typically issue. Outlooks are shown for Issuer Credit Ratings (Moody’s) and Corporate Credit Ratings (S&P) and can be Stable, Negative, or Positive. There is no assurance that the ratings will continue for any given period of time or that they will not be revised by the rating agencies, if in their respective judgments, circumstances warrant. Each rating given by an agency should be evaluated independently of the other agencies’ ratings. The ratings should not be construed as an indication to buy, hold or sell any security.




	Moody’s (A)	S&P (B)
PSEG
Outlook	Stable	Stable
Senior Notes	Baa1	BBB
Commercial Paper	P2	A2
PSE&G
Outlook	Stable	Stable
Mortgage Bonds	Aa3	A
Commercial Paper	P1	A2
PSEG Power
Outlook	Stable	Stable
Senior Notes	Baa1	BBB+


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


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

Other Comprehensive Income

For the year ended December 31, 2019, we had Other Comprehensive Loss of $31 million on a consolidated basis. Other Comprehensive Loss was due primarily to a decrease of $58 million related to pension and other postretirement benefits, and $14 million of unrealized losses on derivative contracts accounted for as hedges, partially offset by $41 million of net unrealized gains related to Available-for-Sale Securities. See Item 8. Note 23. Accumulated Other Comprehensive Income (Loss), Net of Tax for additional information.

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CAPITAL REQUIREMENTS

We expect that all of our capital requirements over the next three years will come from a combination of internally generated funds and external debt financing. Projected capital construction and investment expenditures, excluding nuclear fuel purchases, for the next three years are presented in the table below. These projections include Allowance for Funds Used During Construction and Interest Capitalized During Construction for PSE&G and PSEG Power, respectively. These amounts are subject to change, based on various factors. Amounts shown below for Gas System Modernization, Energy Strong and Clean Energy are for currently approved programs. We intend to continue to invest in infrastructure modernization and will seek to extend these and related programs as appropriate. We will also continue to approach potential growth investments for PSEG Power opportunistically, seeking projects that will provide attractive risk-adjusted returns for our shareholders.




	2020		2021		2022
			Millions
PSE&G:
Transmission	$	1,200	$	950	$	660
Distribution	855		800		920
Gas System Modernization	455		435		405
Energy Strong	110		275		270
Clean Energy	55		55		50
Total PSE&G	$	2,675	$	2,515	$	2,305
PSEG Power:
Baseline	$	125	$	105	$	145
Other	35		10		10
Total PSEG Power	$	160	$	115	$	155
Other	$	25	$	25	$	25
Total PSEG	$	2,860	$	2,655	$	2,485

PSE&G

PSE&G’s projections for future capital expenditures include material additions and replacements to its T&D systems to meet expected growth and to manage reliability. As project scope and cost estimates develop, PSE&G will modify its current projections to include these required investments. PSE&G’s projected expenditures for the various items reported above are primarily comprised of the following:


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


•	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.

In October 2018, we filed our proposed CEF program with the BPU, a six-year estimated $3.5 billion investment program focused on achieving New Jersey’s energy efficiency targets, supporting electric vehicle infrastructure, deploying energy storage, and implementing an EC program which will include installing approximately two million electric smart meters and associated infrastructure. The size and duration of the CEF program, as well as certain other elements of the program, are subject to BPU approval.

The CEF program is not included in PSE&G’s projected capital expenditures in the above table.

In 2019, PSE&G made $2,542 million of capital expenditures, primarily for T&D system reliability. This does not include expenditures for cost of removal, net of salvage, of $108 million, which are included in operating cash flows.

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PSEG Power

PSEG Power’s projected expenditures for the various items listed above are primarily comprised of the following:


•	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.

In 2019, PSEG Power made $482 million of capital expenditures, excluding $125 million for nuclear fuel, primarily related to various projects at Fossil and Nuclear.

Disclosures about Contractual Obligations

The following table reflects our contractual cash obligations in the respective periods in which they are due. In addition, the table summarizes anticipated debt maturities for the years shown. For additional information, see Item 8. Note 16. Debt and Credit Facilities.

The table below does not reflect any anticipated cash payments for pension obligations due to uncertain timing of payments or liabilities for uncertain tax positions since we are unable to reasonably estimate the timing of liability payments in individual years beyond 12 months due to uncertainties in the timing of the effective settlement of tax positions. See Item 8. Note 22. Income Taxes for additional information.




	Total Amount Committed		Less Than 1 Year		2 - 3 Years		4 - 5 Years		Over 5 Years
	Millions
Contractual Cash Obligations
Long-Term Recourse Debt Maturities
PSEG	$	2,450	$	700	$	1,000	$	750	$	—
PSE&G	9,908		259		434		1,575		7,640
PSEG Power	2,850		406		994		950		500
Interest on Recourse Debt
PSEG	185		67		86		32		—
PSE&G	6,146		374		702		660		4,410
PSEG Power	697		123		183		110		281
Operating Leases
PSE&G	126		15		23		17		71
PSEG Power	100		13		28		11		48
Services	165		15		30		30		90
Other	3		1		2		—		—
Energy-Related Purchase Commitments
PSEG Power	2,468		761		854		456		397
Total Contractual Cash Obligations	$	25,098	$	2,734	$	4,336	$	4,591	$	13,437

Liability Payments for Uncertain Tax Positions
PSEG	$	190	$	190	$	—	$	—	$	—
PSE&G	107		107		—		—		—
PSEG Power	77		77		—		—		—

OFF-BALANCE SHEET ARRANGEMENTS

PSEG and PSEG Power issue guarantees, primarily in conjunction with certain of PSEG Power’s energy contracts. See Item 8. Note 15. Commitments and Contingent Liabilities for further discussion.

Through Energy Holdings, we have investments in leveraged leases that are accounted for in accordance with accounting principles generally accepted in the United States (GAAP) for leases. Leveraged lease investments generally involve three

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parties: an owner/lessor, a creditor and a lessee. In a typical leveraged lease arrangement, 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 is not presented on our Consolidated Balance Sheets. In the event of default, the leased asset, and in some cases the lessee, secures the loan. As a lessor, Energy Holdings has ownership rights to the property and rents the property to the lessees for use in their business operations. For additional information, see Item 8. Note 9. Long-Term Investments and Note 10. Financing Receivables.

In the event that collection of the minimum lease payments to be received by Energy Holdings is no longer reasonably assured, Energy Holdings may deem that a lessee has a high probability of defaulting on the lease obligation and would consider the need to record an impairment of its investment. In the event the lease is ultimately rejected by the lessee in a Bankruptcy Court proceeding, the fair value of the underlying asset and the associated debt would be recorded on the Consolidated Balance Sheets instead of the net equity investment in the lease.

CRITICAL ACCOUNTING ESTIMATES

Under GAAP, many accounting standards require the use of estimates, variable inputs and assumptions (collectively referred to as estimates) that are subjective in nature. Because of this, differences between the actual measure realized versus the estimate can have a material impact on results of operations, financial position and cash flows. We have determined that the following estimates are considered critical to the application of rules that relate to the respective businesses.

Accounting for Pensions and OPEB

PSEG sponsors qualified and nonqualified pension plans and OPEB plans covering PSEG’s and its participating affiliates’ current and former employees who meet certain eligibility criteria. In late June 2019, PSEG approved a plan amendment to its qualified pension plan, effective July 1, 2019. The amendment involved the spin-off of predominantly active participants from the existing qualified pension plan (Pension Plan) into a new qualified pension plan (Pension Plan II). See Item 8. Note 14. Pension, Other Postretirement Benefits (OPEB) and Savings Plans for additional information. The market-related value of plan assets held for the qualified pension and OPEB plans is equal to the fair value of these assets as of year-end. The plan assets are comprised of investments in both debt and equity securities which are valued using quoted market prices, broker or dealer quotations, or alternative pricing sources with reasonable levels of price transparency. Plan assets also include investments in unlisted real estate which is valued via third-party appraisals. We calculate pension and OPEB costs using various economic and demographic assumptions.

Assumptions and Approach Used: Economic assumptions include the discount rate and the long-term rate of return on trust assets. Demographic pension and OPEB assumptions include projections of future mortality rates, pay increases and retirement patterns, as well as projected health care costs for OPEB.




Assumption	2019		2018		2017
Pension
Discount Rate	3.30	%	4.41	%	3.73	%
Expected Rate of Return on Plan Assets	7.80	%	7.80	%	7.80	%
OPEB
Discount Rate	3.20	%	4.31	%	3.76	%
Expected Rate of Return on Plan Assets	7.79	%	7.80	%	7.80	%

The discount rate used to calculate pension and OPEB obligations is determined as of December 31 each year, our measurement date. The discount rate is determined by developing a spot rate curve based on the yield to maturity of a universe of high quality corporate bonds with similar maturities to the plan obligations. The spot rates are used to discount the estimated plan distributions. The discount rate is the single equivalent rate that produces the same result as the full spot rate curve.

Our expected rate of return on plan assets reflects current asset allocations, historical long-term investment performance and an estimate of future long-term returns by asset class, long-term inflation assumptions and a premium for active management.

We utilize a corridor approach that reduces the volatility of reported costs/credits. The corridor requires differences between actuarial assumptions and plan results be deferred and amortized as part of the costs/credits. This occurs only when the accumulated differences exceed 10% of the greater of the benefit obligation or the fair value of plan assets as of each year-end. For the Pension Plan, the excess would be amortized over the average remaining expected life of inactive participants, which is

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approximately twenty years. For Pension Plan II, the excess would be amortized over the average remaining service period of active employees, which is approximately fourteen years.

Effect if Different Assumptions Used: As part of the business planning process, we have modeled future costs assuming a 7.70% expected rate of return and a 3.30% discount rate for 2020 pension costs/credits and a 3.20% discount rate for 2020 OPEB costs/credits. Based upon these assumptions, we have estimated a net periodic pension credit in 2020 of approximately $28 million, or $84 million, net of amounts capitalized, and a net periodic OPEB credit in 2020 of approximately $77 million, or $81 million, net of amounts capitalized. Actual future pension costs/credits and funding levels will depend on future investment performance, changes in discount rates, market conditions, funding levels relative to our projected benefit obligation and accumulated benefit obligation and various other factors related to the populations participating in the pension plans. Actual future OPEB costs/credits will depend on future investment performance, changes in discount rates, market conditions, and various other factors.

The following chart reflects the sensitivities associated with a change in certain assumptions. The effects of the assumption changes shown below solely reflect the impact of that specific assumption.




	% Change	Impact on Benefit Obligation as of December 31, 2019		Increase to Costs in 2020		Increase to Costs, net of Amounts Capitalized in 2020
Assumption		Millions
Pension
Discount Rate	(1)%	$	923	$	33	$	22
Expected Rate of Return on Plan Assets	(1)%	N/A		$	57	$	57
OPEB
Discount Rate	(1)%	$	145	$	14	$	13
Expected Rate of Return on Plan Assets	(1)%	N/A		$	5	$	5

See Item 7A. Quantitative and Qualitative Disclosures About Market Risk for additional information.

Derivative Instruments

The operations of PSEG, PSEG Power and PSE&G are exposed to market risks from changes in commodity prices, interest rates and equity prices that could affect their results of operations and financial condition. Exposure to these risks is managed through normal operating and financing activities and, when appropriate, through executing derivative transactions. Derivative instruments are used to create a relationship in which changes to the value of the assets, liabilities or anticipated transactions exposed to market risks are expected to be offset by changes in the value of these derivative instruments.

Current accounting guidance requires us to recognize all derivatives on the balance sheet at their fair value, except for derivatives that qualify for and are designated as normal purchases and normal sales contracts.

Assumptions and Approach Used: In general, the fair value of our derivative instruments is determined primarily by end of day clearing market prices from an exchange, such as the New York Mercantile Exchange, Intercontinental Exchange and Nodal Exchange, or auction prices. Fair values of other energy contracts may be based on broker quotes.

For a small number of contracts where limited observable inputs or pricing information are available, modeling techniques are employed in determination of their fair value using assumptions reflective of contractual terms, current market rates, forward price curves, discount rates and risk factors, as applicable.

For our wholesale energy business, many of the forward sale, forward purchase, option and other contracts are derivative instruments that hedge commodity price risk, but do not meet the requirements for, or are not designated as, either cash flow or fair value hedge accounting. The changes in value of such derivative contracts are marked to market through earnings as the related commodity prices fluctuate. As a result, our earnings may experience significant fluctuations depending on the volatility of commodity prices.

Effect if Different Assumptions Used: Any significant changes to the fair market values of our derivatives instruments could result in a material change in the value of the assets or liabilities recorded on our Consolidated Balance Sheets and could result in a material change to the unrealized gains or losses recorded in our Consolidated Statements of Operations.

For additional information regarding Derivative Financial Instruments, see Item 8. Note 1. Organization, Basis of Presentation and Significant Accounting Policies, Note 18. Financial Risk Management Activities and Note 19. Fair Value Measurements.

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Long-Lived Assets

Management evaluates long-lived assets for impairment and reassesses the reasonableness of their related estimated useful lives whenever events or changes in circumstances warrant assessment. Such events or changes in circumstances may be as a result of significant adverse changes in regulation, business climate, counterparty credit worthiness, market conditions, or a determination that it is more-likely-than-not that an asset or asset group will be sold or retired before its estimated useful life, an asset group’s carrying amount may not be recoverable or an asset’s probability of operating through its estimated remaining useful life changes.

Assumptions and Approach Used: In the event certain triggers exist indicating an asset/asset group may not be recoverable, an undiscounted cash flow test is performed to determine if an impairment exists. When the carrying value of a long-lived asset/asset group exceeds the undiscounted estimate of future cash flows associated with the asset/asset group, an impairment may exist to the extent that the fair value of the asset/asset group is less than its carrying amount. For PSEG Power, cash flows for long-lived assets and asset groups are determined at the lowest level for which identifiable cash flows are largely independent of the cash flows of other assets and liabilities. The cash flows from the generation units are generally evaluated at a regional portfolio level (PJM, NYISO, ISO-NE) along with cash flows generated from the customer supply and risk management activities, inclusive of cash flows from contracts, including those that are accounted for as derivatives and meet the normal purchases and normal sales scope exception. In certain cases, generation assets are evaluated on an individual basis where those assets are individually contracted on a long-term basis with a third party and operations are independent of other generation assets (typically PSEG Power’s solar plants and Kalaeloa). These tests require significant estimates and judgment when developing expected future cash flows. Significant inputs include forward power prices, fuel costs, dispatch rates, other operating and capital expenditures and the cost of borrowing.

In addition, long-lived assets are depreciated under the straight-line method based on estimated useful lives. An asset’s operating useful life is generally based upon operational experience with similar asset types and other non-operational factors. In the ordinary course, management, together with an asset’s co-owners in the case of certain of our jointly-owned assets, makes a number of decisions that impact the operation of our generation assets beyond the current year. These decisions may have a direct impact on the estimated remaining useful lives of our assets and will be influenced by the financial outlook of the assets, including future market conditions such as forward energy and capacity prices, operating and capital investment costs and any state or federal legislation and regulations, among other items.

The assumptions used by management incorporate inherent uncertainties that are at times difficult to predict and could result in impairment charges or accelerated depreciation in future periods if actual results materially differ from the estimated assumptions utilized in our forecasts.

Effect if Different Assumptions Used: The above cash flow tests, and fair value estimates and estimated remaining useful lives may be impacted by a change in the assumptions noted above and could significantly impact the outcome, triggering additional impairment tests, write-offs or accelerated depreciation. For additional information on the potential impacts on our future financial statements that may be caused by a change in useful lives of certain of our generating assets. See Item 8. Note 4. Early Plant Retirements/Asset Dispositions and Note 6. Property, Plant and Equipment and Jointly-Owned Facilities.

Lease Investments

Our Investments in Leases, included in Long-Term Investments on our Consolidated Balance Sheets, are comprised of Lease Receivables (net of non-recourse debt), the estimated residual value of leased assets, and unearned and deferred income. A significant portion of the estimated residual value of leased assets is related to merchant power plants leased to other energy companies. See Item 8. Note 9. Long-Term Investments and Note 10. Financing Receivables.

Assumptions and Approach Used: Residual values are the estimated values of the leased assets at the end of the respective lease per the original lease terms, net of any subsequent impairments. The estimated values are calculated by discounting the cash flows related to the leased assets after the lease term. For the merchant power plants, the estimated discounted cash flows are dependent upon various assumptions, including:


•	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.

In addition, the residual values could be impacted by the intent to sell or terminate the leases. A review of the residual valuations is performed at least annually for each plant subject to lease using specific assumptions tailored to each plant. Those valuations are compared to the recorded residual values to determine if an impairment is warranted.

Effect if Different Assumptions Used: A significant change to the assumptions, such as a large decrease in near-term power prices that affects the market’s view of long-term power prices, could result in an impairment of one or more of the residual values, but not necessarily to all of the residual values. However, if because of changes in assumptions, all the residual values related to the merchant energy plants were deemed to be zero, we would recognize an after-tax charge to income of approximately $49 million.

Asset Retirement Obligations (ARO)

PSE&G, PSEG Power and Services recognize liabilities for the expected cost of retiring long-lived assets for which a legal obligation exists. These AROs are recorded at fair value in the period in which they are incurred and are capitalized as part of the carrying amount of the related long-lived assets. PSE&G, as a rate-regulated entity, recognizes Regulatory Assets or Liabilities as a result of timing differences between the recording of costs and costs recovered through the rate-making process. We accrete the ARO liability to reflect the passage of time with the corresponding expense recorded in O&M Expense.

Assumptions and Approach Used: Because quoted market prices are not available for AROs, we estimate the initial fair value of an ARO by calculating discounted cash flows that are dependent upon various assumptions, including:


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


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


•	discount rates,


•	cost escalation rates,


•	market risk premium,


•	inflation rates, and


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

We obtain updated cost studies triennially unless new information necessitates more frequent updates. The most recent cost study was done in 2018. When we revise any assumptions used to calculate fair values of existing AROs, we adjust the ARO balance and corresponding long-lived asset which generally impacts the amount of accretion and depreciation expense recognized in future periods.

Nuclear Decommissioning AROs

AROs related to the future decommissioning of PSEG Power’s nuclear facilities comprised 95% or $740 million of PSEG Power’s total AROs as of December 31, 2019. PSEG Power determines its AROs for its nuclear units by assigning probability weighting to various discounted cash flow outcomes for each of its nuclear units that incorporate the assumptions above as well as:


•	financial feasibility and impacts on potential early shutdown,


•	license renewals,


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


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


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

Effect if Different Assumptions Used: Changes in the assumptions could result in a material change in the ARO balance sheet obligation and the period over which we accrete to the ultimate liability. Had the following assumptions been applied, our estimates of the approximate impacts on the Nuclear ARO as of December 31, 2019 are as follows:


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


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

Accounting for Regulated Businesses

PSE&G prepares its financial statements to comply with GAAP for rate-regulated enterprises, which differs in some respects from accounting for non-regulated businesses. In general, accounting for rate-regulated enterprises should reflect the economic effects of regulation. As a result, a regulated utility is required to defer the recognition of costs (Regulatory Asset) or recognize obligations (Regulatory Liability) if the rates established are designed to recover the costs and if the competitive environment makes it probable that such rates can be charged or collected. This accounting results in the recognition of revenues and expenses in different time periods than that of enterprises that are not regulated.

Assumptions and Approach Used: PSE&G recognizes Regulatory Assets where it is probable that such costs will be recoverable in future rates from customers and Regulatory Liabilities where it is probable that refunds will be made to customers in future billings. The highest degree of probability is an order from the BPU either approving recovery of the deferred costs over a future period or requiring the refund of a liability over a future period.

Virtually all of PSE&G’s Regulatory Assets and Regulatory Liabilities are supported by BPU orders. In the absence of an order, PSE&G will consider the following when determining whether to record a Regulatory Asset or Liability:


•	past experience regarding similar items with the BPU,


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


•	passage of new legislation, and


•	recent discussions with the BPU.

All deferred costs are subject to prudence reviews by the BPU. When the recovery of a Regulatory Asset or payment of a Regulatory Liability is no longer probable, PSE&G charges or credits earnings, as appropriate.

Effect if Different Assumptions Used: A change in the above assumptions may result in a material impact on our results of operations or our cash flows. See Item 8. Note 7. Regulatory Assets and Liabilities for a description of the amounts and nature of regulatory balance sheet amounts.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT

MARKET RISK

The risk inherent in our market-risk sensitive instruments and positions is the potential loss arising from adverse changes in commodity prices, equity security prices and interest rates as discussed in the Notes to Consolidated Financial Statements. It is our policy to use derivatives to manage risk consistent with business plans and prudent practices. We have a Risk Management Committee comprised of executive officers who utilize a risk oversight function to ensure compliance with our corporate policies and risk management practices.

Additionally, we are exposed to counterparty credit losses in the event of non-performance or non-payment. We have a credit management process, which is used to assess, monitor and mitigate counterparty exposure. In the event of non-performance or non-payment by a major counterparty, there may be a material adverse impact on our financial condition, results of operations or net cash flows.

Commodity Contracts

The availability and price of energy-related commodities are subject to fluctuations from factors such as weather, environmental policies, changes in supply and demand, state and federal regulatory policies, market rules and other events. To reduce price risk caused by market fluctuations, we enter into supply contracts and derivative contracts, including forwards, futures, swaps and options with approved counterparties. These contracts, in conjunction with physical sales and other services, help reduce risk and optimize the value of owned electric generation capacity.

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Value-at-Risk (VaR) Models

VaR represents the potential losses, under normal market conditions, for instruments or portfolios due to changes in market factors, for a specified time period and confidence level. We estimate VaR across our commodity businesses.

MTM VaR consists of MTM derivatives that are economic hedges. The MTM VaR calculation does not include market risks associated with activities that are subject to accrual accounting, primarily our generating facilities and some load-serving activities.

The VaR models used are variance/covariance models adjusted for the change of positions with 95% and 99.5% confidence levels and a one-day holding period for the MTM activities. The models assume no new positions throughout the holding periods; however, we actively manage our portfolio.




	MTM VaR
	Millions
Years Ended December 31,	2019		2018

95% Confidence Level, Loss could exceed VaR one day in 20 days
Period End	$	9	$	21
Average for the Period	$	12	$	14
High	$	35	$	46
Low	$	5	$	6

99.5% Confidence Level, Loss could exceed VaR one day in 200 days
Period End	$	14	$	32
Average for the Period	$	19	$	22
High	$	54	$	72
Low	$	8	$	9

See Item 8. Note 18. Financial Risk Management Activities for a discussion of credit risk.

Interest Rates

We are subject to the risk of fluctuating interest rates in the normal course of business. We manage interest rate risk by targeting a balanced debt maturity profile which limits refinancing in any given period or interest rate environment. In addition, we use a mix of fixed and floating rate debt, interest rate swaps and interest rate lock agreements.

As of December 31, 2019, a hypothetical 10% increase in market interest rates would result in


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


•	a $401 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.

Debt and Equity Securities

We have $6.5 billion of assets in a trust for our pension and OPEB plans. Although fluctuations in market prices of securities within this portfolio do not directly affect our earnings in the current period, changes in the value of these investments could affect


•	our future contributions to these plans,


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


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

The NDT Fund is comprised primarily of fixed income and equity securities. As of December 31, 2019, the portfolio included $1.2 billion of equity securities and $1.1 billion in fixed income securities. The fair market value of the assets in the NDT Fund will fluctuate primarily depending upon the performance of equity markets. As of December 31, 2019, a hypothetical 10% change in the equity market would impact the value of the equity securities in the NDT Fund by approximately $115 million.

We use duration to measure the interest rate sensitivity of the fixed income portfolio. Duration is a summary statistic of the effective average maturity of the fixed income portfolio. The benchmark for the fixed income component of the NDT Fund

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currently has a duration of 5.87 years and a yield of 2.32%. The portfolio’s value will appreciate or depreciate by the duration with a 1% change in interest rates. As of December 31, 2019, a hypothetical 1% increase in interest rates would result in a decline in the market value for the fixed income portfolio of approximately $62 million.

Credit Risk

See Item 8. Note 18. Financial Risk Management Activities for a discussion of credit risk and a discussion about PSEG Power’s and PSE&G’s credit risk.

Energy Holdings has credit risk related to its investments in leases, which totaled $169 million, net of deferred taxes of $328 million, as of December 31, 2019. These leveraged leases are concentrated in the U.S. energy industry. See Item 8. Note 10. Financing Receivables for counterparties’ credit ratings and other information. The credit exposure to the lessees is partially mitigated through various credit enhancement mechanisms within the lease transactions. These credit enhancement features vary from lease to lease. Credit enhancements include affiliate guarantees and partial collateralization of the lessee with non-leased assets.

In any lease transaction, in the event of a default, Energy Holdings would exercise its rights and attempt to seek recovery of its investment. The results of such efforts may not be known for a period of time. A bankruptcy of a lessee and failure to recover adequate value could lead to a foreclosure of the lease. Under a worst-case scenario, if a foreclosure were to occur, Energy Holdings would record a pre-tax write-off up to its outstanding gross investment in these facilities. Also, in the event of a potential foreclosure, the amount and timing of any potential reduction in net tax benefits generated by Energy Holdings’ portfolio of investments is dependent upon a number of factors including, but not limited to, the time of a potential foreclosure, any cash trapped at the projects and negotiations during such potential foreclosure process. The potential loss of earnings, impairment and/or tax payments could have a material impact to our financial position, results of operations and net cash flows.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

This combined Form 10-K is separately filed by PSEG, PSE&G and PSEG Power. Information contained herein relating to any individual company is filed by such company on its own behalf. PSE&G and PSEG Power each make representations only as to itself and make no representations as to any other company.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of

Public Service Enterprise Group Incorporated

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Public Service Enterprise Group Incorporated and subsidiaries (the “Company” or PSEG) as of December 31, 2019 and 2018, the related consolidated statements of operations, comprehensive income, stockholders' equity, and cash flows for each of the three years in the period ended December 31, 2019, the related notes and the consolidated financial statement schedule listed in the Index at Item 15(B)(a) (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the consolidated financial position of the Company as of December 31, 2019 and 2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019, in conformity with accounting principles generally accepted in the United States of America.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company's internal control over financial reporting as of December 31, 2019, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated February 26, 2020, expressed an unqualified opinion on the Company's internal control over financial reporting.

Basis for Opinion

These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matters

The critical audit matters communicated below are matters arising from the current-period audit of the financial statements that were communicated or required to be communicated to the audit committee and that (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.

Early Plant Retirements/Asset Dispositions - Nuclear - Refer to Notes 4 and 13 to the financial statements

Critical Audit Matter Description

PSEG’s wholly-owned subsidiary PSEG Power LLC (PSEG Power) owns and operates nuclear plants in New Jersey and has recorded associated asset retirement obligations (ARO) for their eventual decommissioning. In April 2019, the New Jersey Board of Public Utilities (BPU) awarded Zero Emission Certificates (ZEC) to PSEG Power’s Salem 1, Salem 2 and Hope Creek nuclear plants for an initial period of approximately three years through May 2022. As described in Note 4, there are certain legal, regulatory, and economic matters in the markets in which these nuclear plants operate, which, if not favorably resolved, would result in PSEG taking all necessary steps to retire all of these nuclear plants subsequent to the initial ZEC period at or prior to a scheduled refueling outage, which is significantly in advance of their currently estimated remaining

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useful lives. This would result in material charges associated with accelerated depreciation and amortization, impairment charges, and accelerated asset retirement costs, among other costs.

We identified the potential early retirement of the nuclear plants as a critical audit matter because of the significant estimates and assumptions management made in determining the nuclear plants’ useful lives and in evaluating the recorded investments in the nuclear plants for potential impairment. Further, management’s estimates used in recording the ARO included a number of assumptions, including the timing of cash flows associated with the eventual decommissioning of the nuclear plants following the retirement of the assets. Auditing each of these assumptions required a high degree of auditor judgment.

How the Critical Audit Matter Was Addressed in the Audit

Our audit procedures related to the potential early retirement of the nuclear plants and the related impact on the recorded investments in the nuclear plants and the related ARO included the following, among others:


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


•	We tested the effectiveness of controls over the evaluation of 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.

Commitments and Contingent Liabilities - Passaic River Environmental Liability - Refer to Note 15 to the financial statements

Critical Audit Matter Description

As described in Note 15, the U.S. Environmental Protection Agency (EPA) has designated a 17-mile stretch of the lower Passaic River (Lower Passaic River Study Area (LPRSA)) in New Jersey as a superfund site requiring environmental remediation and has identified certain potentially responsible parties (PRPs), including PSEG’s subsidiaries Public Service Electric and Gas Company (PSE&G) and PSEG Power. The EPA has released a Record of Decision (ROD) for the LPRSA’s lower 8.3 miles that requires the removal of sediments at an estimated cost of $2.3 billion (ROD Remedy). An EPA-commenced process to allocate the associated costs to the PRPs is underway, and PSEG cannot predict the outcome. Additionally, one of the PRPs has filed suit against PSE&G and others seeking cost recovery and contribution under the Federal Comprehensive Environmental Response, Compensation and Liability Act of 1980, but has not quantified alleged damages. The litigation is ongoing and PSEG cannot predict the outcome. As of December 31, 2019, PSEG recorded an environmental liability for its estimated share of the remediation of the environmental contamination, a portion of which has been deferred as a regulatory asset based on PSE&G’s assessment that it will recover such costs in future rates.

The outcome of this matter is uncertain, and PSEG cannot predict this matter’s ultimate impact on its financial statements. It is possible that PSEG will record additional costs beyond what it has accrued, and that such costs could be material, but PSEG cannot at the current time estimate the amount or range of any additional costs.

We identified the accounting for the Passaic River environmental liability as a critical audit matter due to the uncertainties inherent in estimating PSEG’s liability. Auditing PSEG’s allocable share of the remediation cost, the environmental liability recorded, and the evaluation of future recovery of the regulatory asset recorded by PSE&G required a high degree of auditor judgment and the involvement of our environmental specialists.

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How the Critical Audit Matter Was Addressed in the Audit

Our audit procedures related to the Passaic River environmental liability included the following, among others:


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

Regulatory Assets and Liabilities - Income Taxes - Refer to Notes 7 and 22 to the financial statements

Critical Audit Matter Description

PSEG’s subsidiary, PSE&G, is an electric and gas transmission and distribution utility regulated by the BPU and the Federal Energy Regulatory Commission (FERC). Management believes that PSE&G’s transmission and distribution businesses continue to meet the accounting requirements for rate-regulated entities, and PSE&G’s financial statements reflect the economic effects of cost-based rate regulation. PSE&G defers the recognition of costs (regulatory assets) or records the recognition of obligations (regulatory liabilities) if it is probable that, through the rate-making process, there will be a corresponding increase or decrease in future rates. Accordingly, PSE&G has deferred certain costs and recoveries, which are being amortized over various future periods. To the extent that collection of any such costs or payment of liabilities becomes no longer probable as a result of changes in regulation and/or competitive position, the associated regulatory asset or regulatory liability is charged or credited to income.

Through the rate-making process, PSE&G’s rates to customers also include the recovery of income tax expense associated with PSE&G’s electric and gas distribution and electric transmission operations. As a result of the 2017 Tax Cuts and Jobs Act, which reduced the federal corporate income tax rate from 35% to 21%, PSE&G recorded regulatory liabilities for excess accumulated deferred income taxes (ADIT). These regulatory liabilities will be refunded to customers in future periods. PSE&G’s most recent electric and gas distribution base rate case, concluded in 2018, established the tax adjustment credit (TAC) that provides for the refund of these excess ADIT regulatory liabilities as well as the flow through to customers of historical and current accumulated deferred income taxes for tax-deductible repairs. The flow through of the current tax benefits results in lower revenues and lower income tax expense, as well as the recognition of a regulatory asset, as management believes it is probable that the accumulated tax benefits, treated as a flow-through item to PSE&G customers, will be recovered from customers in the future. The accounting for the return of the excess ADIT and the flow-through results in an annual effective tax rate for PSE&G and PSEG that is currently significantly lower than the statutory tax rate.

We identified the accounting for the TAC as a critical audit matter due to the complexity in accounting for the impact of rate regulation on income tax expense. Auditing the significant judgments made by management to support its assertion that the TAC regulatory assets are probable of future recovery required auditor judgment and specialized knowledge of accounting matters specific to rate regulation. Further, the determination of the estimated benefit of current tax-deductible repairs under the Internal Revenue Code, and the resulting impacts on the TAC regulatory asset and income tax expense recorded in the financial statements was complex and required the involvement of our income tax specialists.

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How the Critical Audit Matter Was Addressed in the Audit

Our audit procedures to evaluate the accounting for the impact of rate regulation on income tax expense and associated regulatory assets and regulatory liabilities included the following, among others:


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


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


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


•	With the assistance of our income tax specialists, we tested the accuracy of 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.

/s/ DELOITTE & TOUCHE LLP

Parsippany, New Jersey

February 26, 2020

We have served as the Company's auditor since 1934.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Sole Stockholder of

Public Service Electric and Gas Company

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Public Service Electric and Gas Company and subsidiaries (the “Company”) as of December 31, 2019 and 2018, and the related consolidated statements of operations, comprehensive income, common stockholder’s equity, and cash flows for each of the three years in the period ended December 31, 2019, the related notes and the consolidated financial statement schedule listed in the Index at Item 15(B)(b) (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2019 and 2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019, in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ DELOITTE & TOUCHE LLP

Parsippany, New Jersey

February 26, 2020

We have served as the Company's auditor since 1934.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Sole Member of

PSEG Power LLC

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of PSEG Power LLC and subsidiaries (the “Company”) as of December 31, 2019 and 2018, the related consolidated statements of operations, comprehensive income, member’s equity, and cash flows for each of the three years in the period ended December 31, 2019, the related notes and the consolidated financial statement schedule listed in the Index at Item 15(B)(c) (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2019 and 2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019, in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

/s/ DELOITTE & TOUCHE LLP

Parsippany, New Jersey

February 26, 2020

We have served as the Company's auditor since 2000.

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PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

CONSOLIDATED STATEMENTS OF OPERATIONS

Millions, except per share data




	Years Ended December 31,
	2019			2018			2017
OPERATING REVENUES	$	10,076		$	9,696		$	9,094
OPERATING EXPENSES
Energy Costs	3,372			3,225			2,778
Operation and Maintenance	3,111			3,069			2,901
Depreciation and Amortization	1,248			1,158			1,986
(Gain) Loss on Asset Dispositions	402			(54		)	—
Total Operating Expenses	8,133			7,398			7,665
OPERATING INCOME	1,943			2,298			1,429
Income from Equity Method Investments	14			15			14
Net Gains (Losses) on Trust Investments	260			(143		)	134
Other Income (Deductions)	125			85			82
Non-Operating Pension and OPEB Credits (Costs)	177			76			—
Interest Expense	(569		)	(476		)	(391		)
INCOME BEFORE INCOME TAXES	1,950			1,855			1,268
Income Tax Benefit (Expense)	(257		)	(417		)	306
NET INCOME	$	1,693		$	1,438		$	1,574
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:
BASIC	504			504			505
DILUTED	507			507			507
NET INCOME PER SHARE:
BASIC	$	3.35		$	2.85		$	3.12
DILUTED	$	3.33		$	2.83		$	3.10

See Notes to Consolidated Financial Statements.

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PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

Millions




	Years Ended December 31,
		2019			2018			2017
NET INCOME		$	1,693		$	1,438		$	1,574
Other Comprehensive Income (Loss), net of tax
Unrealized Gains (Losses) on Available-for-Sale Securities, net of tax (expense) benefit of $(26), $11 and $(37) for the years ended 2019, 2018 and 2017, respectively		41			(17		)	44
Unrealized Gains (Losses) on Cash Flow Hedges, net of tax (expense) benefit of $6, $1, and $1 for the years ended 2019, 2018 and 2017, respectively		(14		)	(1		)	(2		)
Pension/OPEB adjustment, net of tax (expense) benefit of $18, $(18) and $(4) for the years ended 2019, 2018 and 2017, respectively		(58		)	46			(8		)
Other Comprehensive Income (Loss), net of tax		(31		)	28			34
COMPREHENSIVE INCOME		$	1,662		$	1,466		$	1,608

See Notes to Consolidated Financial Statements.

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PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

CONSOLIDATED BALANCE SHEETS

Millions




	December 31,
	2019			2018
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents	$	147		$	177
Accounts Receivable, net of allowances of $60 in 2019 and $63 in 2018	1,313			1,435
Tax Receivable	21			242
Unbilled Revenues	239			240
Fuel	310			331
Materials and Supplies, net	587			571
Prepayments	79			94
Derivative Contracts	113			11
Regulatory Assets	351			389
Assets Held for Sale	30			—
Other	41			17
Total Current Assets	3,231			3,507
PROPERTY, PLANT AND EQUIPMENT	45,944			44,201
Less: Accumulated Depreciation and Amortization	(10,100		)	(9,838		)
Net Property, Plant and Equipment	35,844			34,363
NONCURRENT ASSETS
Regulatory Assets	3,677			3,399
Operating Lease Right-of-Use Assets	282			—
Long-Term Investments	812			896
Nuclear Decommissioning Trust (NDT) Fund	2,216			1,878
Long-Term Tax Receivable	150			—
Long-Term Receivable of Variable Interest Entity	813			624
Rabbi Trust Fund	246			224
Goodwill	—			16
Other Intangibles	149			143
Derivative Contracts	24			1
Other	286			275
Total Noncurrent Assets	8,655			7,456
TOTAL ASSETS	$	47,730		$	45,326

See Notes to Consolidated Financial Statements.

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PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

CONSOLIDATED BALANCE SHEETS

Millions




	December 31,
	2019			2018
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES
Long-Term Debt Due Within One Year	$	1,365		$	1,294
Commercial Paper and Loans	1,115			1,016
Accounts Payable	1,358			1,451
Derivative Contracts	36			11
Accrued Interest	116			110
Accrued Taxes	41			26
Clean Energy Program	143			143
Obligation to Return Cash Collateral	119			136
Regulatory Liabilities	234			311
Other	520			437
Total Current Liabilities	5,047			4,935
NONCURRENT LIABILITIES
Deferred Income Taxes and Investment Tax Credits (ITC)	6,256			5,713
Regulatory Liabilities	3,002			3,221
Operating Leases	273			—
Asset Retirement Obligations	1,087			1,063
Other Postretirement Benefit (OPEB) Costs	734			704
OPEB Costs of Servco	626			501
Accrued Pension Costs	952			791
Accrued Pension Costs of Servco	171			109
Environmental Costs	349			327
Derivative Contracts	1			4
Long-Term Accrued Taxes	182			181
Other	218			232
Total Noncurrent Liabilities	13,851			12,846
COMMITMENTS AND CONTINGENT LIABILITIES (See Note 15)
CAPITALIZATION
LONG-TERM DEBT	13,743			13,168
STOCKHOLDERS’ EQUITY
Common Stock, no par, authorized 1,000 shares; issued, 2019 and 2018— 534 shares	5,003			4,980
Treasury Stock, at cost, 2019 and 2018—30 shares	(831		)	(808		)
Retained Earnings	11,406			10,582
Accumulated Other Comprehensive Loss	(489		)	(377		)
Total Stockholders’ Equity	15,089			14,377
Total Capitalization	28,832			27,545
TOTAL LIABILITIES AND CAPITALIZATION	$	47,730		$	45,326

See Notes to Consolidated Financial Statements.

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PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

CONSOLIDATED STATEMENTS OF CASH FLOWS

Millions




	Years Ended December 31,
	2019			2018			2017
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	1,693		$	1,438		$	1,574
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	1,248			1,158			1,986
Amortization of Nuclear Fuel	178			187			199
(Gain) Loss on Asset Dispositions	402			(54		)	—
Emission Allowances and Renewable Energy Credit (REC) Compliance Accrual	108			97			103
Provision for Deferred Income Taxes (Other than Leases) and ITC	180			568			(167		)
Non-Cash Employee Benefit Plan (Credits) Costs	(48		)	70			89
Leveraged Lease (Income) Loss, Adjusted for Rents Received and Deferred Taxes	(14		)	(149		)	(159		)
Net (Gain) Loss on Lease Investments	32			5			48
Net Realized and Unrealized (Gains) Losses on Energy Contracts and Other Derivatives	(290		)	116			188
Cost of Removal	(108		)	(160		)	(107		)
Net Change in Regulatory Assets and Liabilities	25			(153		)	(188		)
Net (Gains) Losses and (Income) Expense from NDT Fund	(296		)	98			(156		)
Net Change in Certain Current Assets and Liabilities:
Tax Receivable	77			17			65
Accrued Taxes	(9		)	(69		)	16
Cash Collateral	349			(247		)	(90		)
Other Current Assets and Liabilities	(145		)	70			(72		)
Employee Benefit Plan Funding and Related Payments	(39		)	(101		)	(81		)
Other	36			22			12
Net Cash Provided By (Used In) Operating Activities	3,379			2,913			3,260
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment	(3,166		)	(3,912		)	(4,190		)
Purchase of Emissions Allowances and RECs	(98		)	(146		)	(117		)
Proceeds from Sales of Trust Investments	1,787			1,501			2,319
Purchases of Trust Investments	(1,814		)	(1,473		)	(2,340		)
Other	146			114			72
Net Cash Provided By (Used In) Investing Activities	(3,145		)	(3,916		)	(4,256		)
CASH FLOWS FROM FINANCING ACTIVITIES
Net Change in Commercial Paper and Loans	99			474			154
Issuance of Long-Term Debt	1,900			2,750			2,175
Redemption of Long-Term Debt	(1,250		)	(1,350		)	(500		)
Cash Dividends Paid on Common Stock	(950		)	(910		)	(870		)
Other	(56		)	(77		)	(74		)
Net Cash Provided By (Used In) Financing Activities	(257		)	887			885
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash	(23		)	(116		)	(111		)
Cash, Cash Equivalents and Restricted Cash at Beginning of Period	199			315			426
Cash, Cash Equivalents and Restricted Cash at End of Period	$	176		$	199		$	315
Supplemental Disclosure of Cash Flow Information:
Income Taxes Paid (Received)	$	41		$	99		$	(8	)
Interest Paid, Net of Amounts Capitalized	$	539		$	454		$	377
Accrued Property, Plant and Equipment Expenditures	$	499		$	517		$	722

See Notes to Consolidated Financial Statements.

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PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

Millions




	Common Stock			Treasury Stock					Retained Earnings			Accumulated Other Comprehensive Income (Loss)
	Shs.	Amount		Shs.		Amount			Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total
Balance as of January 1, 2017	534	$	4,936	(29	)	$	(717	)	$	9,174		$	(263	)	$	13,130
Net Income	—	—		—		—			1,574			—			1,574
Other Comprehensive Income (Loss), net of tax (expense) benefit of $(40)	—	—		—		—			—			34			34
Comprehensive Income															1,608
Cash Dividends at $1.72 per share on Common Stock	—	—		—		—			(870		)	—			(870		)
Other	—	25		—		(46		)	—			—			(21		)
Balance as of December 31, 2017	534	$	4,961	(29	)	$	(763	)	$	9,878		$	(229	)	$	13,847
Net Income	—	—		—		—			1,438			—			1,438
Cumulative Effect Adjustment to Reclassify Unrealized Net Gains on Equity Investments	—	—		—		—			176			(176		)	—
Other Comprehensive Income (Loss), net of tax (expense) benefit of $(6)	—	—		—		—			—			28			28
Comprehensive Income															1,466
Cash Dividends at $1.80 per share on Common Stock	—	—		—		—			(910		)	—			(910		)
Other	—	19		(1	)	(45		)	—			—			(26		)
Balance as of December 31, 2018	534	$	4,980	(30	)	$	(808	)	$	10,582		$	(377	)	$	14,377
Net Income	—	—		—		—			1,693			—			1,693
Cumulative Effect Adjustment to Reclassify Stranded Tax Effects Resulting from the Change in the Federal Corporate Income Tax Rate	—	—		—		—			81			(81		)	—
Other Comprehensive Income (Loss), net of tax (expense) benefit of $(2)	—	—		—		—			—			(31		)	(31		)
Comprehensive Income															1,662
Cash Dividends at $1.88 per share on Common Stock	—	—		—		—			(950		)	—			(950		)
Other	—	23		—		(23		)	—			—			—
Balance as of December 31, 2019	534	$	5,003	(30	)	$	(831	)	$	11,406		$	(489	)	$	15,089

See Notes to Consolidated Financial Statements.

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PUBLIC SERVICE ELECTRIC AND GAS COMPANY

CONSOLIDATED STATEMENTS OF OPERATIONS

Millions




	Years Ended December 31,
	2019			2018			2017
OPERATING REVENUES	$	6,625		$	6,471		$	6,324
OPERATING EXPENSES
Energy Costs	2,738			2,520			2,421
Operation and Maintenance	1,581			1,575			1,458
Depreciation and Amortization	837			770			685
Total Operating Expenses	5,156			4,865			4,564
OPERATING INCOME	1,469			1,606			1,760
Net Gains (Losses) on Trust Investments	2			(1		)	2
Other Income (Deductions)	83			80			85
Non-Operating Pension and OPEB Credits (Costs)	150			59			(8		)
Interest Expense	(361		)	(333		)	(303		)
INCOME BEFORE INCOME TAXES	1,343			1,411			1,536
Income Tax Expense	(93		)	(344		)	(563		)
NET INCOME	$	1,250		$	1,067		$	973

See disclosures regarding Public Service Electric and Gas Company included in the Notes to Consolidated Financial Statements.

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PUBLIC SERVICE ELECTRIC AND GAS COMPANY

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

Millions




	Years Ended December 31,
		2019		2018			2017
NET INCOME		$	1,250	$	1,067		$	973
Other Comprehensive Income (Loss), net of tax
Unrealized Gains (Losses) on Available-for-Sale Securities, net of tax (expense) benefit of $(1), $1 and $0 for the years ended 2019, 2018 and 2017, respectively		3		(1		)	(1		)
COMPREHENSIVE INCOME		$	1,253	$	1,066		$	972

See disclosures regarding Public Service Electric and Gas Company included in the Notes to Consolidated Financial Statements.

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PUBLIC SERVICE ELECTRIC AND GAS COMPANY

CONSOLIDATED BALANCE SHEETS

Millions




	December 31,
	2019			2018
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents	$	21		$	39
Accounts Receivable, net of allowances of $60 in 2019 and $63 in 2018	901			879
Tax Receivable	—			20
Accounts Receivable—Affiliated Companies	1			123
Unbilled Revenues	239			240
Materials and Supplies, net	213			196
Prepayments	35			10
Regulatory Assets	351			389
Other	28			11
Total Current Assets	1,789			1,907
PROPERTY, PLANT AND EQUIPMENT	33,900			31,633
Less: Accumulated Depreciation and Amortization	(6,623		)	(6,277		)
Net Property, Plant and Equipment	27,277			25,356
NONCURRENT ASSETS
Regulatory Assets	3,677			3,399
Operating Lease Right-of-Use Assets	98			—
Long-Term Investments	248			270
Rabbi Trust Fund	48			45
Other	129			132
Total Noncurrent Assets	4,200			3,846
TOTAL ASSETS	$	33,266		$	31,109

See disclosures regarding Public Service Electric and Gas Company included in the Notes to Consolidated Financial Statements.

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PUBLIC SERVICE ELECTRIC AND GAS COMPANY

CONSOLIDATED BALANCE SHEETS

Millions




	December 31,
	2019		2018
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES
Long-Term Debt Due Within One Year	$	259	$	500
Commercial Paper and Loans	362		272
Accounts Payable	639		713
Accounts Payable—Affiliated Companies	390		321
Accrued Interest	91		84
Clean Energy Program	143		143
Obligation to Return Cash Collateral	119		136
Regulatory Liabilities	234		311
Other	436		345
Total Current Liabilities	2,673		2,825
NONCURRENT LIABILITIES
Deferred Income Taxes and ITC	4,189		3,830
Regulatory Liabilities	3,002		3,221
Operating Leases	87		—
Asset Retirement Obligations	303		302
OPEB Costs	495		486
Accrued Pension Costs	501		400
Environmental Costs	294		268
Long-Term Accrued Taxes	115		69
Other	136		124
Total Noncurrent Liabilities	9,122		8,700
COMMITMENTS AND CONTINGENT LIABILITIES (See Note 15)
CAPITALIZATION
LONG-TERM DEBT	9,568		8,684
STOCKHOLDER’S EQUITY
Common Stock; 150 shares authorized; issued and outstanding, 2019 and 2018—132 shares	892		892
Contributed Capital	1,095		1,095
Basis Adjustment	986		986
Retained Earnings	8,928		7,928
Accumulated Other Comprehensive Income (Loss)	2		(1		)
Total Stockholder’s Equity	11,903		10,900
Total Capitalization	21,471		19,584
TOTAL LIABILITIES AND CAPITALIZATION	$	33,266	$	31,109

See disclosures regarding Public Service Electric and Gas Company included in the Notes to Consolidated Financial Statements.

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PUBLIC SERVICE ELECTRIC AND GAS COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

Millions




	Years Ended December 31,
	2019			2018			2017
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	1,250		$	1,067		$	973
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	837			770			685
Provision for Deferred Income Taxes and ITC	(28		)	405			616
Non-Cash Employee Benefit Plan (Credits) Costs	(62		)	37			50
Cost of Removal	(108		)	(160		)	(107		)
Net Change in Other Regulatory Assets and Liabilities	25			(153		)	(188		)
Net Change in Certain Current Assets and Liabilities
Accounts Receivable and Unbilled Revenues	(18		)	65			(106		)
Materials and Supplies	(14		)	1			(13		)
Prepayments	(9		)	14			(35		)
Accounts Payable	(59		)	64			1
Accounts Receivable/Payable—Affiliated Companies, net	203			(139		)	101
Other Current Assets and Liabilities	62			5			15
Employee Benefit Plan Funding and Related Payments	(21		)	(85		)	(68		)
Other	(23		)	(38		)	(86		)
Net Cash Provided By (Used In) Operating Activities	2,035			1,853			1,838
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment	(2,542		)	(2,896		)	(2,919		)
Proceeds from Sales of Trust Investments	36			20			36
Purchases of Trust Investments	(34		)	(22		)	(37		)
Solar Loan Investments	8			(5		)	7
Other	10			9			10
Net Cash Provided By (Used In) Investing Activities	(2,522		)	(2,894		)	(2,903		)
CASH FLOWS FROM FINANCING ACTIVITIES
Net Change in Commercial Paper and Loans	90			272			—
Issuance of Long-Term Debt	1,150			1,350			775
Redemption of Long-Term Debt	(500		)	(750		)	—
Contributed Capital	—			—			150
Cash Dividend Paid	(250		)	—			—
Other	(14		)	(14		)	(9		)
Net Cash Provided By (Used In) Financing Activities	476			858			916
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash	(11		)	(183		)	(149		)
Cash, Cash Equivalents and Restricted Cash at Beginning of Period	61			244			393
Cash, Cash Equivalents and Restricted Cash at End of Period	$	50		$	61		$	244
Supplemental Disclosure of Cash Flow Information:
Income Taxes Paid (Received)	$	(48	)	$	94		$	(104	)
Interest Paid, Net of Amounts Capitalized	$	343		$	318		$	294
Accrued Property, Plant and Equipment Expenditures	$	335		$	350		$	429

See disclosures regarding Public Service Electric and Gas Company included in the Notes to Consolidated Financial Statements.

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PUBLIC SERVICE ELECTRIC AND GAS COMPANY

CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER’S EQUITY

Millions




	Common Stock		Contributed Capital		Basis Adjustment		Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total
Balance as of January 1, 2017	$	892	$	945	$	986	$	5,888		$	1		$	8,712
Net Income	—		—		—		973			—			973
Other Comprehensive Income (Loss), net of tax (expense) benefit of $0	—		—		—		—			(1		)	(1		)
Comprehensive Income													972
Contributed Capital	—		150		—		—			—			150
Balance as of December 31, 2017	$	892	$	1,095	$	986	$	6,861		$	—		$	9,834
Net Income	—		—		—		1,067			—			1,067
Other Comprehensive Income (Loss), net of tax (expense) benefit of $1	—		—		—		—			(1		)	(1		)
Comprehensive Income													1,066
Balance as of December 31, 2018	$	892	$	1,095	$	986	$	7,928		$	(1	)	$	10,900
Net Income	—		—		—		1,250			—			1,250
Other Comprehensive Income (Loss), net of tax (expense) benefit of $(1)	—		—		—		—			3			3
Comprehensive Income													1,253
Cash Dividends Paid	—		—		—		(250		)	—			(250		)
Balance as of December 31, 2019	$	892	$	1,095	$	986	$	8,928		$	2		$	11,903

See disclosures regarding Public Service Electric and Gas Company included in the Notes to Consolidated Financial Statements.

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PSEG POWER LLC

CONSOLIDATED STATEMENTS OF OPERATIONS

Millions




	Years Ended December 31,
	2019			2018			2017
OPERATING REVENUES	$	4,385		$	4,146		$	3,860
OPERATING EXPENSES
Energy Costs	2,118			2,197			1,913
Operation and Maintenance	1,040			1,053			1,046
Depreciation and Amortization	377			354			1,268
(Gain) Loss on Asset Dispositions	402			(54		)	—
Total Operating Expenses	3,937			3,550			4,227
OPERATING INCOME (LOSS)	448			596			(367		)
Income from Equity Method Investments	14			15			14
Net Gains (Losses) on Trust Investments	253			(140		)	125
Other Income (Deductions)	54			21			20
Non-Operating Pension and OPEB (Costs) Credits	21			15			8
Interest Expense	(119		)	(76		)	(50		)
INCOME (LOSS) BEFORE INCOME TAXES	671			431			(250		)
Income Tax Benefit (Expense)	(203		)	(66		)	729
NET INCOME	$	468		$	365		$	479

See disclosures regarding PSEG Power LLC included in the Notes to Consolidated Financial Statements.

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PSEG POWER LLC

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

Millions




	Years Ended December 31,
		2019			2018			2017
NET INCOME		$	468		$	365		$	479
Other Comprehensive Income (Loss), net of tax
Unrealized Gains (Losses) on Available-for-Sale Securities, net of tax (expense) benefit of $(22), $9, and $(39) for the years ended 2019, 2018 and 2017, respectively		32			(13		)	46
Pension/OPEB adjustment, net of tax (expense) benefit of $13, $(16) and $(3) for the years ended 2019, 2018 and 2017, respectively		(45		)	41			(7		)
Other Comprehensive Income (Loss), net of tax		(13		)	28			39
COMPREHENSIVE INCOME		$	455		$	393		$	518

See disclosures regarding PSEG Power LLC included in the Notes to Consolidated Financial Statements.

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PSEG POWER LLC

CONSOLIDATED BALANCE SHEETS

Millions




	December 31,
	2019			2018
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents	$	21		$	22
Accounts Receivable	309			477
Accounts Receivable—Affiliated Companies	408			274
Short-Term Loan to Affiliate	149			—
Fuel	310			331
Materials and Supplies, net	372			373
Derivative Contracts	113			11
Prepayments	11			14
Assets Held for Sale	28			—
Other	5			5
Total Current Assets	1,726			1,507
PROPERTY, PLANT AND EQUIPMENT	11,699			12,224
Less: Accumulated Depreciation and Amortization	(3,273		)	(3,382		)
Net Property, Plant and Equipment	8,426			8,842
NONCURRENT ASSETS
Operating Lease Right-of-Use Assets	71			—
NDT Fund	2,216			1,878
Long-Term Investments	66			86
Goodwill	—			16
Other Intangibles	149			143
Rabbi Trust Fund	62			56
Derivative Contracts	24			1
Other	65			65
Total Noncurrent Assets	2,653			2,245
TOTAL ASSETS	$	12,805		$	12,594

See disclosures regarding PSEG Power LLC included in the Notes to Consolidated Financial Statements.

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PSEG POWER LLC

CONSOLIDATED BALANCE SHEETS

Millions




	December 31,
	2019			2018
LIABILITIES AND MEMBER’S EQUITY
CURRENT LIABILITIES
Long-Term Debt Due Within One Year	$	406		$	44
Accounts Payable	505			498
Accounts Payable—Affiliated Companies	5			16
Short-Term Loan from Affiliate	—			193
Derivative Contracts	31			11
Accrued Interest	21			21
Other	91			59
Total Current Liabilities	1,059			842
NONCURRENT LIABILITIES
Deferred Income Taxes and ITC	1,876			1,619
Operating Leases	62			—
Asset Retirement Obligations	781			758
OPEB Costs	192			176
Accrued Pension Costs	284			246
Derivative Contracts	1			4
Long-Term Accrued Taxes	115			76
Other	111			122
Total Noncurrent Liabilities	3,422			3,001
COMMITMENTS AND CONTINGENT LIABILITIES (See Note 15)
LONG-TERM DEBT	2,434			2,791
MEMBER’S EQUITY
Contributed Capital	2,214			2,214
Basis Adjustment	(986		)	(986		)
Retained Earnings	5,063			5,051
Accumulated Other Comprehensive Loss	(401		)	(319		)
Total Member’s Equity	5,890			5,960
TOTAL LIABILITIES AND MEMBER’S EQUITY	$	12,805		$	12,594

See disclosures regarding PSEG Power LLC included in the Notes to Consolidated Financial Statements.

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PSEG POWER LLC

CONSOLIDATED STATEMENTS OF CASH FLOWS

Millions




	Years Ended December 31,
	2019			2018			2017
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	468		$	365		$	479
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	377			354			1,268
Amortization of Nuclear Fuel	178			187			199
(Gain) Loss on Asset Dispositions	402			(54		)	—
Emission Allowances and Renewable Energy Credit (REC) Compliance Accrual	108			97			103
Provision for Deferred Income Taxes and ITC	248			206			(807		)
Non-Cash Employee Benefit Plan Costs	7			23			28
Interest Accretion on Asset Retirement Obligation	40			41			30
Net Realized and Unrealized (Gains) Losses on Energy Contracts and Other Derivatives	(290		)	116			188
Net (Gains) Losses and (Income) Expense from NDT Fund	(296		)	98			(156		)
Net Change in Certain Current Assets and Liabilities
Fuel, Materials and Supplies	(1		)	(39		)	42
Cash Collateral	349			(247		)	(90		)
Accounts Receivable	(32		)	51			(45		)
Accounts Payable	5			(13		)	39
Accounts Receivable/Payable—Affiliated Companies, net	(112		)	(56		)	(2		)
Other Current Assets and Liabilities	14			(40		)	10
Employee Benefit Plan Funding and Related Payments	(11		)	(9		)	(7		)
Other	25			4			47
Net Cash Provided By (Used In) Operating Activities	1,479			1,084			1,326
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment	(607		)	(996		)	(1,231		)
Purchase of Emissions Allowances and RECs	(98		)	(146		)	(117		)
Proceeds from Sales of Trust Investments	1,658			1,423			2,182
Purchases of Trust Investments	(1,685		)	(1,392		)	(2,199		)
Short-Term Loan to Affiliate	(149		)	—			87
Other	120			60			46
Net Cash Provided By (Used In) Investing Activities	(761		)	(1,051		)	(1,232		)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of Long-Term Debt	—			700			—
Cash Dividend Paid	(525		)	(400		)	(350		)
Redemption of Long-Term Debt	—			(250		)	—
Short-Term Loan from Affiliate	(193		)	(88		)	281
Other	(1		)	(5		)	(4		)
Net Cash Provided By (Used In) Financing Activities	(719		)	(43		)	(73		)
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash	(1		)	(10		)	21
Cash, Cash Equivalents and Restricted Cash at Beginning of Period	22			32			11
Cash, Cash Equivalents and Restricted Cash at End of Period	$	21		$	22		$	32
Supplemental Disclosure of Cash Flow Information:
Income Taxes Paid (Received)	$	(41	)	$	(92	)	$	77
Interest Paid, Net of Amounts Capitalized	$	113		$	73		$	48
Accrued Property, Plant and Equipment Expenditures	$	164		$	167		$	293

See disclosures regarding PSEG Power LLC included in the Notes to Consolidated Financial Statements.

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PSEG POWER LLC

CONSOLIDATED STATEMENTS OF MEMBER’S EQUITY

Millions




	Contributed Capital		Basis Adjustment			Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total
Balance as of January 1, 2017	$	2,214	$	(986	)	$	4,782		$	(211	)	$	5,799
Net Income	—		—			479			—			479
Other Comprehensive Income (Loss), net of tax (expense) benefit of $(42)	—		—			—			39			39
Comprehensive Income												518
Cash Dividends Paid	—		—			(350		)	—			(350		)
Balance as of December 31, 2017	$	2,214	$	(986	)	$	4,911		$	(172	)	$	5,967
Net Income	—		—			365			—			365
Cumulative Effect Adjustment to Reclassify Unrealized Net Gains on Equity Investments	—		—			175			(175		)	—
Other Comprehensive Income (Loss), net of tax (expense) benefit of $(7)	—		—			—			28			28
Comprehensive Income												393
Cash Dividends Paid	—		—			(400		)	—			(400		)
Balance as of December 31, 2018	$	2,214	$	(986	)	$	5,051		$	(319	)	$	5,960
Net Income	—		—			468			—			468
Cumulative Effect Adjustment to Reclassify Stranded Tax Effects Resulting from the Change in the Federal Corporate Income Tax Rate	—		—			69			(69		)	—
Other Comprehensive Income (Loss), net of tax (expense) benefit of $(9)	—		—			—			(13		)	(13		)
Comprehensive Income												455
Cash Dividends Paid	—		—			(525		)	—			(525		)
Balance as of December 31, 2019	$	2,214	$	(986	)	$	5,063		$	(401	)	$	5,890

See disclosures regarding PSEG Power LLC included in the Notes to Consolidated Financial Statements.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1. Organization, Basis of Presentation and Summary of Significant Accounting Policies

Public Service Enterprise Group Incorporated (PSEG) is a holding company with a diversified business mix within the energy industry. Its operations are primarily in the Northeastern and Mid-Atlantic United States and in other select markets. PSEG’s principal direct wholly owned subsidiaries are:

•

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

•

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

PSEG’s other direct wholly owned subsidiaries are: PSEG Long Island LLC (PSEG LI), which operates the Long Island Power Authority’s (LIPA) electric transmission and distribution (T&D) system under an Operations Services Agreement (OSA); PSEG Energy Holdings L.L.C. (Energy Holdings), which primarily has investments in leveraged leases; and PSEG Services Corporation (Services), which provides certain management, administrative and general services to PSEG and its subsidiaries at cost.

Basis of Presentation

The respective financial statements included herein have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (SEC) applicable to Annual Reports on Form 10-K and in accordance with accounting guidance generally accepted in the United States (GAAP).

Significant Accounting Policies

Principles of Consolidation

Each company consolidates those entities in which it has a controlling interest or is the primary beneficiary. See Note 5. Variable Interest Entity. Entities over which the companies exhibit significant influence, but do not have a controlling interest and/or are not the primary beneficiary, are accounted for under the equity method of accounting. For investments in which significant influence does not exist and the investor is not the primary beneficiary, the cost method of accounting is applied. All significant intercompany accounts and transactions are eliminated in consolidation.

PSE&G and PSEG Power also have undivided interests in certain jointly-owned facilities, with each responsible for paying its respective ownership share of construction costs, fuel purchases and operating expenses. PSE&G and PSEG Power consolidate their portion of any revenues and expenses related to their respective jointly-owned facilities in the appropriate revenue and expense categories.

Accounting for the Effects of Regulation

In accordance with accounting guidance for rate-regulated entities, PSE&G’s financial statements reflect the economic effects of regulation. PSE&G defers the recognition of costs (a Regulatory Asset) or records the recognition of obligations (a Regulatory Liability) if it is probable that, through the rate-making process, there will be a corresponding increase or decrease in future rates. Accordingly, PSE&G has deferred certain costs and recoveries, which are being amortized over various future periods. To the extent that collection of any such costs or payment of liabilities becomes no longer probable as a result of changes in regulation and/or competitive position, the associated Regulatory Asset or Liability is charged or credited to income. Management believes that PSE&G’s T&D businesses continue to meet the accounting requirements for rate-regulated entities. For additional information, see Note 7. Regulatory Assets and Liabilities.

Cash, Cash Equivalents and Restricted Cash

Cash equivalents consist of short-term, highly liquid investments with original maturities of three months or less. Restricted cash consists primarily of deposits received related to various construction projects at PSE&G.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following provides a reconciliation of cash, cash equivalents and restricted cash reported within the Consolidated Balance Sheets that sum to the total of the same such amounts in the Consolidated Statements of Cash Flows for the years ended December 31, 2018 and 2019.




	PSE&G		PSEG Power		Other (A)		Consolidated
	Millions
As of December 31, 2018
Cash and Cash Equivalents	$	39	$	22	$	116	$	177
Restricted Cash in Other Current Assets	8		—		—		8
Restricted Cash in Other Noncurrent Assets	14		—		—		14
Cash, Cash Equivalents and Restricted Cash	$	61	$	22	$	116	$	199
As of December 31, 2019
Cash and Cash Equivalents	$	21	$	21	$	105	$	147
Restricted Cash in Other Current Assets	11		—		—		11
Restricted Cash in Other Noncurrent Assets	18		—		—		18
Cash, Cash Equivalents and Restricted Cash	$	50	$	21	$	105	$	176


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

Derivative Instruments

Each company uses derivative instruments to manage risk pursuant to its business plans and prudent practices.

Within PSEG and its affiliate companies, PSEG Power has the most exposure to commodity price risk. PSEG Power is exposed to commodity price risk primarily relating to changes in the market price of electricity, fossil fuels and other commodities. Fluctuations in market prices result from changes in supply and demand, fuel costs, market conditions, weather, state and federal regulatory policies, environmental policies, transmission availability and other factors. PSEG Power uses a variety of derivative and non-derivative instruments, such as financial options, futures, swaps, fuel purchases and forward purchases and sales of electricity, to manage the exposure to fluctuations in commodity prices and optimize the value of PSEG Power’s expected generation. Changes in the fair market value of the derivative contracts are recorded in earnings.

Determining whether a contract qualifies as a derivative requires that management exercise significant judgment, including assessing the contract’s market liquidity. PSEG has determined that contracts to purchase and sell certain products do not meet the definition of a derivative under the current authoritative guidance since they do not provide for net settlement, or the markets are not sufficiently liquid to conclude that physical forward contracts are readily convertible to cash.

Under current authoritative guidance, all derivatives are recognized on the balance sheet at their fair value, except for derivatives that are designated as normal purchases and normal sales (NPNS). Further, derivatives that qualify for hedge accounting can be designated as fair value or cash flow hedges. For fair value hedges, changes in fair values for both the derivative and the underlying hedged exposure are recognized in earnings each period.

Certain offsetting derivative assets and liabilities are subject to a master netting or similar agreement. In general, the terms of the agreements provide that in the event of an early termination the counterparties have the right to offset amounts owed or owing under that and any other agreement with the same counterparty. Accordingly, these positions are offset on the Consolidated Balance Sheets of PSEG Power and PSEG.

For cash flow hedges, the gain or loss on a derivative instrument designated and qualifying as a cash flow hedge is deferred in Accumulated Other Comprehensive Income (Loss) until earnings are affected by the variability of cash flows of the hedged transaction.

For derivative contracts that do not qualify or are not designated as cash flow or fair value hedges or as NPNS, changes in fair value are recorded in current period earnings. PSEG does not currently elect fair value or cash flow hedge accounting on its commodity derivative positions.

Contracts that qualify for, and are designated, as NPNS are accounted for upon settlement. Contracts which qualify for NPNS are contracts for which physical delivery is probable, they will not be financially settled, and the quantities under contract are expected to be used or sold in the normal course of business over a reasonable period of time.

For additional information regarding derivative financial instruments, see Note 18. Financial Risk Management Activities.

Revenue Recognition

PSE&G’s regulated electric and gas revenues are recorded primarily based on services rendered to customers. PSE&G records unbilled revenues for the estimated amount customers will be billed for services rendered from the time meters were last read to

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

the end of the respective accounting period. The unbilled revenue is estimated each month based on usage per day, the number of unbilled days in the period, estimated seasonal loads based upon the time of year and the variance of actual degree-days and temperature-humidity-index hours of the unbilled period from expected norms.

Regulated revenues from the transmission of electricity are recognized as services are provided based on a FERC-approved annual formula rate mechanism. This mechanism provides for an annual filing of estimated revenue requirement with rates effective January 1 of each year. After completion of the annual period ending December 31, PSE&G files a true-up whereby it compares its actual revenue requirement to the original estimate to determine any over or under collection of revenue. PSE&G records the estimated financial statement impact of the difference between the actual and the filed revenue requirement as a refund or deferral for future recovery when such amounts are probable and can be reasonably estimated in accordance with accounting guidance for rate-regulated entities.

The majority of PSEG Power’s revenues relate to bilateral contracts, which are accounted for on the accrual basis as the energy is delivered. PSEG Power’s revenue also includes changes in the value of energy derivative contracts that are not designated as NPNS. See Note 18. Financial Risk Management Activities for further discussion.

PJM Interconnection, L.L.C. (PJM), the Independent System Operator-New England (ISO-NE) and the New York Independent System Operator (NYISO) facilitate the dispatch of energy and energy-related products. PSEG Power generally reports electricity sales and purchases conducted with those individual ISOs on a net hourly basis in either Revenues or Energy Costs in its Consolidated Statement of Operations, the classification of which depends on the net hourly activity. Capacity revenue and expense are also reported net based on PSEG Power’s monthly net sale or purchase position in the individual ISOs.

PSEG LI is the primary beneficiary of Long Island Electric Utility Servco, LLC (Servco). For transactions in which Servco acts as principal, Servco records revenues and the related pass-through expenditures separately in Operating Revenues and Operations and Maintenance (O&M) Expense, respectively. See Note 5. Variable Interest Entity for further information.

For additional information regarding Revenues, see Note 3. Revenues.

Depreciation and Amortization (D&A)

PSE&G calculates depreciation under the straight-line method based on estimated average remaining lives of the several classes of depreciable property. These estimates are reviewed on a periodic basis and necessary adjustments are made as approved by the BPU or FERC. The average depreciation rate stated as a percentage of original cost of depreciable property was as follows:




	2019		2018		2017
	Avg Rate		Avg Rate		Avg Rate
Electric Transmission	2.41	%	2.42	%	2.41	%
Electric Distribution	2.54	%	2.51	%	2.51	%
Gas Distribution	1.85	%	1.61	%	1.63	%

PSEG Power calculates depreciation on generation-related assets under the straight-line method based on the assets’ estimated useful lives. The estimated useful lives are:


•	general plant assets—3 years to 20 years


•	fossil production assets—30 years to 56 years


•	nuclear generation assets—approximately 60 years


•	pumped storage facilities—76 years


•	solar assets—25 years to 35 years

Allowance for Funds Used During Construction (AFUDC) and Interest Capitalized During Construction (IDC)

AFUDC represents the cost of debt and equity funds used to finance the construction of new utility assets at PSE&G. IDC represents the cost of debt used to finance construction at PSEG Power. The amount of AFUDC or IDC capitalized as Property, Plant and Equipment is included as a reduction of interest charges or other income for the equity portion. The amounts and average rates used to calculate AFUDC or IDC for the years ended December 31, 2019, 2018 and 2017 were as follows:

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS




	AFUDC/IDC Capitalized
	2019				2018				2017
	Millions		Avg Rate		Millions		Avg Rate		Millions		Avg Rate
PSE&G	$	81	7.22	%	$	70	7.74	%	$	73	7.42	%
PSEG Power	$	27	4.60	%	$	67	4.60	%	$	78	4.60	%

Income Taxes

PSEG and its subsidiaries file a consolidated federal income tax return and income taxes are allocated to PSEG’s subsidiaries based on the taxable income or loss of each subsidiary on a separate return basis in accordance with a tax-sharing agreement between PSEG and each of its affiliated subsidiaries. Allocations between PSEG and its subsidiaries are recorded through intercompany accounts. Investment tax credits deferred in prior years are being amortized over the useful lives of the related property.

Uncertain income tax positions are accounted for using a benefit recognition model with a two-step approach, a more-likely-than-not recognition criterion and a measurement attribute that measures the position as the largest amount of tax benefit that is greater than 50% likely of being realized upon ultimate settlement. If it is not more-likely-than-not that the benefit will be sustained on its technical merits, no benefit will be recorded. Uncertain tax positions that relate only to timing of when an item is included on a tax return are considered to have met the recognition threshold. See Note 22. Income Taxes for further discussion.

Impairment of Long-Lived Assets and Leveraged Leases

Management evaluates long-lived assets for impairment whenever events or changes in circumstances, such as significant adverse changes in regulation, business climate, counterparty credit worthiness or market conditions, including prolonged periods of adverse commodity and capacity prices or a current expectation that a long-lived asset will be sold or disposed of significantly before the end of its previously estimated useful life, could potentially indicate an asset’s or asset group’s carrying amount may not be recoverable. In such an event, an undiscounted cash flow analysis is performed to determine if an impairment exists. When a long-lived asset’s or asset group’s carrying amount exceeds the associated undiscounted estimated future cash flows, the asset/asset group is considered impaired to the extent that its fair value is less than its carrying amount. An impairment would result in a reduction of the value of the long-lived asset/asset group through a non-cash charge to earnings. See Note 4. Early Plant Retirements/Asset Dispositions for more information.

For PSEG Power, cash flows for long-lived assets and asset groups are determined at the lowest level for which identifiable cash flows are largely independent of the cash flows of other assets and liabilities. The cash flows from the generation units are generally evaluated at a regional portfolio level (PJM, NYISO, ISO-NE) along with cash flows generated from the customer supply and risk management activities, inclusive of cash flows from contracts, including those that are accounted for as derivatives and meet the NPNS scope exception. In certain cases, generation assets are evaluated on an individual basis where those assets are individually contracted on a long-term basis with a third party and operations are independent of other generation assets (typically PSEG Power’s solar plants and Kalaeloa).

Energy Holdings’ leveraged leases are comprised of Lease Receivables (net of non-recourse debt), the estimated residual value of leased assets, and unearned and deferred income. Residual values are the estimated values of the leased assets at the end of the respective lease per the original lease terms, net of any subsequent impairments. A review of the residual valuations, which are calculated by discounting the cash flows related to the leased assets after the lease term, is performed at least annually for each asset subject to lease using specific assumptions tailored to each asset. Those valuations are compared to the recorded residual values to determine if an impairment is warranted.

Accounts Receivable—Allowance for Doubtful Accounts

PSE&G’s accounts receivable are reported in the balance sheet as gross outstanding amounts adjusted for doubtful accounts. The allowance for doubtful accounts reflects PSE&G’s best estimates of losses on the accounts receivable balances. The allowance is based on accounts receivable aging, historical experience, write-off forecasts and other currently available evidence.

Accounts receivable are charged off in the period in which the receivable is deemed uncollectible. Recoveries of accounts receivable are recorded when it is known they will be received.

Materials and Supplies and Fuel

PSE&G’s and PSEG Power’s materials and supplies are carried at average cost and charged to inventory when purchased and expensed or capitalized to Property, Plant and Equipment, as appropriate, when installed or used. Fuel inventory at PSEG Power is valued at the lower of average cost or market and includes stored natural gas, coal, fuel oil and propane used to

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

generate power and to satisfy obligations under PSEG Power’s gas supply contracts with PSE&G. The costs of fuel, including initial transportation costs, are included in inventory when purchased and charged to Energy Costs when used or sold. The cost of nuclear fuel is capitalized within Property, Plant and Equipment and amortized to fuel expense using the units-of-production method.

Property, Plant and Equipment

PSE&G’s additions to and replacements of existing property, plant and equipment are capitalized at cost. The cost of maintenance, repair and replacement of minor items of property is charged to expense as incurred. At the time units of depreciable property are retired or otherwise disposed of, the original cost, adjusted for net salvage value, is charged to accumulated depreciation.

PSEG Power capitalizes costs, including those related to its jointly-owned facilities, which increase the capacity, improve or extend the life of an existing asset, represent a newly acquired or constructed asset or represent the replacement of a retired asset. The cost of maintenance, repair and replacement of minor items of property is charged to appropriate expense accounts as incurred. Environmental costs are capitalized if the costs mitigate or prevent future environmental contamination or if the costs improve existing assets’ environmental safety or efficiency. All other environmental expenditures are expensed as incurred. PSEG Power also capitalizes spare parts that meet specific criteria. Capitalized spares are depreciated over the remaining lives of their associated assets.

Leases

Effective January 1, 2019, PSEG and its subsidiaries adopted new accounting guidance. See Note 2. Recent Accounting Standards for additional information.

PSEG and its subsidiaries, when acting as lessee or lessor, determine if an arrangement is a lease at inception. PSEG assesses contracts to determine if the arrangement conveys (i) the right to control the use of the identified property, (ii) the right to obtain substantially all of the economic benefits from the use of the property, and (iii) the right to direct the use of the property.

PSEG and its subsidiaries are neither the lessee nor the lessor in any material leases that are not classified as operating leases.

Lessee—Operating Lease Right-of-Use Assets represent the right to use an underlying asset for the lease term and Operating Lease Liabilities represent the obligation to make lease payments arising from the lease. Operating Lease Right-of-Use Assets and Operating Lease Liabilities are recognized at the lease commencement date based on the present value of lease payments over the lease term.

The current portion of Operating Lease Liabilities is included in Other Current Liabilities. Operating Lease Right-of-Use Assets and noncurrent Operating Lease Liabilities are included as separate captions in Noncurrent Assets and Noncurrent Liabilities, respectively, on the Consolidated Balance Sheets of PSEG, PSE&G and PSEG Power. PSEG and its subsidiaries do not recognize Operating Lease Right-of-Use Assets and Operating Lease Liabilities for leases where the term is twelve months or less.

PSEG and its subsidiaries recognize the lease payments on a straight-line basis over the term of the leases and variable lease payments in the period in which the obligations for those payments are incurred.

As lessee, most of the operating leases of PSEG and its subsidiaries do not provide an implicit rate; therefore, incremental borrowing rates are used based on the information available at commencement date in determining the present value of lease payments. The implicit rate is used when readily determinable. PSE&G’s incremental borrowing rates are based on secured borrowing rates. PSEG’s and PSEG Power’s incremental borrowing rates are generally unsecured rates. Having calculated simulated secured rates for each of PSEG and PSEG Power, it was determined that the difference between the unsecured borrowing rates and the simulated secured rates had an immaterial effect on their recorded Operating Lease Right-of-Use Assets and Operating Lease Liabilities. Services, PSEG LI and other subsidiaries of PSEG that do not borrow funds or issue debt may enter into leases. Since these companies do not have credit ratings and related incremental borrowing rates, PSEG has determined that it is appropriate for these companies to use the incremental borrowing rate of PSEG, the parent company.

Lease terms may include options to extend or terminate the lease when it is reasonably certain that such options will be exercised.

PSEG and its subsidiaries have lease agreements with lease and non-lease components. For real estate, equipment and vehicle leases, the lease and non-lease components are accounted for as a single lease component.

Lessor—Property subject to operating leases, where PSEG or one of its subsidiaries is the lessor, is included in Property, Plant and Equipment and rental income from these leases is included in Operating Revenues.

PSEG and its subsidiaries, have lease agreements with lease and non-lease components, which are primarily related to real estate assets and solar generating facilities. PSEG and subsidiaries account for the lease and non-lease components as a single lease component.

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Energy Holdings is the lessor in leveraged leases. Leveraged lease accounting guidance is grandfathered for existing leveraged leases. Energy Holdings’ leveraged leases are accounted for in Operating Revenues and in Noncurrent Long-Term Investments. If modified after January 1, 2019, those leveraged leases will be accounted for as operating or financing leases. See Note 9. Long-Term Investments and Note 10. Financing Receivables.

See Note 8. Leases for detailed information on leases.

Trust Investments

These securities comprise the Nuclear Decommissioning Trust (NDT) Fund, a master independent external trust account maintained to provide for the costs of decommissioning upon termination of operations of PSEG Power’s nuclear facilities and amounts that are deposited to fund a Rabbi Trust which was established to meet the obligations related to non-qualified pension plans and deferred compensation plans.

Effective January 1, 2018, unrealized gains and losses on equity security investments are recorded in Net Income instead of Other Comprehensive Income (Loss). The debt securities continue to be classified as available-for-sale with the unrealized gains and losses recorded as a component of Accumulated Other Comprehensive Income (Loss). Realized gains and losses on both equity and available-for-sale debt security investments are recorded in earnings and are included with the unrealized gains and losses on equity securities in Net Gains (Losses) on Trust Investments. Other-than-temporary impairments on NDT and Rabbi Trust debt securities are also included in Net Gains (Losses) on Trust Investments. See Note 11. Trust Investments for further discussion.

Pension and Other Postretirement Benefits (OPEB) Plans

The market-related value of plan assets held for the qualified pension and OPEB plans is equal to the fair value of those assets as of year-end. Fair value is determined using quoted market prices and independent pricing services based upon the security type as reported by the trustee at the measurement date (December 31) as well as investments in unlisted real estate which is valued via third-party appraisals.

PSEG recognizes a long-term receivable primarily related to future funding by LIPA of Servco’s recognized pension and OPEB liabilities. This receivable is presented separately on the Consolidated Balance Sheet of PSEG as a noncurrent asset.

Pursuant to the OSA, Servco records expense for contributions to its pension plan trusts and for OPEB payments made to retirees.

See Note 14. Pension, Other Postretirement Benefits (OPEB) and Savings Plans for further discussion.

Basis Adjustment

PSE&G and PSEG Power have recorded a Basis Adjustment in their respective Consolidated Balance Sheets related to the generation assets that were transferred from PSE&G to PSEG Power in August 2000 at the price specified by the BPU. Because the transfer was between affiliates, the transaction was recorded at the net book value of the assets and liabilities rather than the transfer price. The difference between the total transfer price and the net book value of the generation-related assets and liabilities, $986 million, net of tax, was recorded as a Basis Adjustment on PSE&G’s and PSEG Power’s Consolidated Balance Sheets. The $986 million is an addition to PSE&G’s Common Stockholder’s Equity and a reduction of PSEG Power’s Member’s Equity. These amounts are eliminated on PSEG’s consolidated financial statements.

Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Note 2. Recent Accounting Standards

New Standards Adopted in 2019

Leases—Accounting Standards Update (ASU) 2016-02, updated by ASUs 2018-01, 2018-10, 2018-11, 2018-20 and 2019-01

This accounting standard, and related updates, replace existing lease accounting guidance and require lessees to recognize leases with a term greater than 12 months on the balance sheet using a right-of-use asset approach. At lease commencement, a lessee will recognize a lease asset and corresponding lease obligation. A lessee will classify its leases as either finance leases or operating leases and a lessor will classify its leases as operating leases, direct financing leases, or sales-type leases. The standard requires additional disclosure of key information. Existing guidance related to leveraged leases does not change.

PSEG adopted the optional transition method on January 1, 2019. There was no cumulative effect adjustment required to be

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recorded to Retained Earnings at adoption. The optional transition method requires disclosure under Accounting Standards Codification (ASC) 840—Leases, the previously existing lease guidance for prior periods.

PSEG elected various practical expedients allowed by the standard, including the package of three practical expedients related to not reassessing existing or expired contracts and initial direct costs; and excluding evaluation of land easements that exist or expired before adoption that were not previously accounted for as leases.

The impact of adoption on PSEG’s Consolidated Balance Sheet was to record Operating Lease Right-of-Use Assets of $261 million and Operating Lease Liabilities of $282 million. As part of that impact, PSEG reclassified deferred rent incentives and deferred rent liabilities of approximately $21 million, which were previously classified as Other Noncurrent Liabilities, to Operating Lease Right-of-Use Assets in accordance with this standard. PSE&G’s assets and liabilities each increased by $91 million and PSEG Power’s assets and liabilities each increased by $46 million. PSEG’s adoption of this standard did not have a material impact on the Consolidated Statements of Operations or Consolidated Statements of Cash Flows of PSEG, PSE&G and PSEG Power. See Note 8. Leases for additional information.

Derivatives and Hedging: Targeted Improvements to Accounting for Hedging Activities—ASU 2017-12, updated by ASU 2018-16 and 2019-04

This accounting standard’s amendments more closely align hedge accounting with companies’ risk management activities in the financial statements and ease the operational burden of applying hedge accounting.

PSEG adopted this standard on January 1, 2019. The standard requires using a modified retrospective method upon adoption. PSEG analyzed the impact of this standard on its consolidated financial statements and determined that the standard could enable PSEG to enter into certain transactions that can be deemed hedges that previously would not have qualified. Adoption of this standard did not have a material impact on the financial statements of PSEG, PSE&G and PSEG Power.

Premium Amortization on Purchased Callable Debt Securities—ASU 2017-08

This accounting standard was issued to shorten the amortization period for certain callable debt securities held at a premium. Specifically, the standard requires the premium to be amortized to the earliest call date.

PSEG adopted this standard on January 1, 2019 on a modified retrospective basis through a cumulative effect adjustment directly to Retained Earnings as of the beginning of 2019. Adoption of this standard did not have a material impact on the financial statements of PSEG, PSE&G and PSEG Power.

Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income—ASU 2018-02

This accounting standard affects any entity that is required to apply the provisions of the ASC topic, “Income Statement-Reporting Comprehensive Income,” and has items of Other Comprehensive Income for which the related tax effects are presented in Other Comprehensive Income as required by GAAP. Specifically, this standard allows entities to record a reclassification from Accumulated Other Comprehensive Income to Retained Earnings for stranded tax effects resulting from the recent decrease in the federal corporate income tax rate.

PSEG adopted this standard on January 1, 2019. The impact of adoption on PSEG’s Consolidated Balance Sheet was to increase Retained Earnings and Accumulated Other Comprehensive Loss by approximately $81 million. PSEG Power’s Retained Earnings and Accumulated Other Comprehensive Loss increased by approximately $69 million. The impact on PSE&G’s Consolidated Balance Sheet was immaterial. PSEG’s adoption of this standard did not have a material impact on the Consolidated Statements of Operations or Consolidated Statements of Cash Flows of PSEG, PSE&G and PSEG Power.

Simplifying the Test for Goodwill Impairment—ASU 2017-04

This accounting standard requires an entity to perform its annual or interim goodwill impairment test by comparing the fair value of a reporting unit with its carrying amount. An entity should recognize an impairment charge for the amount by which the carrying amount exceeds the reporting unit’s fair value; however, the loss recognized should not exceed the total amount of goodwill allocated to that reporting unit. Additionally, an entity should consider income tax effects from any tax deductible goodwill on the carrying amount of the reporting unit when measuring the goodwill impairment loss, if applicable.

This standard requires application on a prospective basis and disclosure of the nature of and reason for the change in accounting principle upon transition. The new standard is effective for impairment tests for periods beginning January 1, 2020. Early adoption is permitted for interim or annual goodwill impairment tests performed on testing dates after January 1, 2017. PSEG early adopted this standard in the fourth quarter of 2019. See Note 12. Goodwill and Other Intangibles.

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New Standards Issued But Not Yet Adopted As of December 31, 2019

Measurement of Credit Losses on Financial Instruments—ASU 2016-13, updated by ASU 2018-19, 2019-04, 2019-05, 2019-11 and 2020-02

This accounting standard provides a new model for recognizing credit losses on financial assets. The new model requires entities to use an estimate of expected credit losses that will be recognized as an impairment allowance rather than a direct write-down of the amortized cost basis. The estimate of expected credit losses is to be based on past events, current conditions and supportable forecasts over a reasonable period. For purchased financial assets with credit deterioration, a similar model is to be used; however, the initial allowance will be added to the purchase price rather than reported as an allowance. Credit losses on available-for-sale debt securities will be measured in a manner similar to current GAAP; however, this standard requires those credit losses to be presented as an allowance, rather than a write-down. This new standard also requires additional disclosures of the allowance for credit losses by financial asset type, including disclosures of credit quality indicators for each class of financial asset disaggregated by year of origination.

The standard is effective for annual and interim periods beginning after December 15, 2019. PSEG adopted this standard on January 1, 2020 on a modified retrospective basis through a cumulative effect charge to Retained Earnings. The impact of adoption of this standard was immaterial on the financial statements of PSEG, PSE&G and PSEG Power.

Disclosure Framework—Changes to the Disclosure Requirements for Fair Value Measurement—ASU 2018-13

This accounting standard modifies the disclosure requirements for fair value measurements. Certain current disclosure requirements relating to Level 3 fair value measurements, and transfers between Level 1 and Level 2 fair value measurements will be eliminated. The standard will also add certain other disclosure requirements for Level 3 fair value measurements.

The standard is effective for annual and interim periods beginning after December 15, 2019. Certain amendments in the standard will be applied prospectively for only the most recent interim or annual period presented in the initial fiscal year of adoption. All other amendments of the standard will be applied retrospectively to all periods presented upon their effective date. Early adoption is permitted.

Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract—ASU 2018-15

This accounting standard aligns the capitalization requirements for implementation costs incurred in a hosting arrangement that is a service contract with capitalization requirements for implementation costs incurred to develop or obtain internal-use software, including hosting arrangements that include an internal-use software license. The standard follows the guidance in ASC 350—Intangibles—Goodwill and Other to determine which implementation costs to capitalize as an asset related to the service contract and which costs to expense. The standard requires the amortization of capitalized costs to be presented in O&M Expense. In addition, the standard also adds presentation requirements for these costs in the statements of cash flows and financial position.

The standard is effective for annual and interim periods beginning after December 15, 2019. Early adoption is permitted, including adoption in any interim period. This standard can be applied either retrospectively or prospectively to all implementation costs incurred after the date of adoption. PSEG adopted this standard prospectively on January 1, 2020. PSEG, PSE&G and PSEG Power do not expect a material impact on their respective financial statements.

Targeted Improvements to Related Party Guidance for Variable Interest Entities (VIE)-ASU 2018-17

This accounting standard improves the VIE guidance in the area of decision-making fees. Consistent with how indirect interests held through related parties under common control are considered for determining whether a reporting entity must consolidate a VIE, indirect interests held through related parties in common control arrangements will be considered on a proportional basis for determining whether fees paid to decision makers and service providers are variable interests.

This standard is effective for annual and interim periods beginning after December 15, 2019. The standard is required to be applied retrospectively with a cumulative effect adjustment to Retained Earnings at the beginning of the earliest period presented. Early adoption is permitted. PSEG adopted this standard on January 1, 2020. Adoption of this standard did not have an impact on the financial statements of PSEG, PSE&G and PSEG Power.

Disclosure Framework—Changes to the Disclosure Requirements for Defined Benefit Plans—ASU 2018-14

This accounting standard modifies the disclosure requirements for employers that sponsor defined benefit pension or other postretirement plans, including the elimination of certain current disclosure requirements. Certain other disclosure requirements related to interest crediting rates have been added and certain clarifications were made to other disclosure requirements.

The standard is effective for fiscal years ending after December 15, 2020 and early adoption is permitted. Amendments in this standard will be applied on a retrospective basis to all periods presented.

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Simplifying the Accounting for Income Taxes—ASU 2019-12

This accounting standard simplifies the accounting for income taxes, including the elimination of certain exceptions to current requirements. Certain other requirements related to franchise taxes that are partially based on income, step-up of tax basis of goodwill and allocation of consolidated taxes to legal entities have been added and certain clarifications were made to other requirements.

The standard is effective for fiscal years beginning after December 15, 2020 and early adoption is permitted. Certain amendments in this standard will be applied on a retrospective basis to all periods presented. Certain other amendments will be applied on either a retrospective basis for all periods presented or a modified retrospective basis through a cumulative effect adjustment to Retained Earnings as of the beginning of the fiscal year of adoption. All other amendments will be applied on a prospective basis. PSEG is currently analyzing the impact of this standard on its financial statements.

Clarifying the Interactions between Investments-Equity Securities, Investments-Equity Method and Joint Ventures, and Derivatives and Hedging—ASU 2020-01

This accounting standard clarifies that an entity should consider transaction prices for purposes of measuring the fair value of certain equity securities immediately before applying or upon discontinuing the equity method. This accounting standard also clarifies that when accounting for contracts entered into to purchase equity securities, an entity should not consider whether, upon the settlement of the forward contract or exercise of the purchased option, the underlying securities would be accounted for under the equity method or the fair value option.

The standard is effective for fiscal years beginning after December 15, 2020. Amendments in this standard will be applied prospectively. Under a prospective transition, PSEG will apply the amendments at the beginning of the interim period that includes the adoption date. PSEG is currently analyzing the impact of this standard on its financial statements.

Note 3. Revenues

Nature of Goods and Services

The following is a description of principal activities by reportable segment from which PSEG, PSE&G and PSEG Power generate their revenues.

PSE&G

Revenues from Contracts with Customers

Electric and Gas Distribution and Transmission Revenues—PSE&G sells gas and electricity to customers under default commodity supply tariffs. PSE&G’s regulated electric and gas default commodity supply and distribution services are separate tariffs which are satisfied as the product(s) and/or services are delivered to the customer. The electric and gas commodity and delivery tariffs are recurring contracts in effect until modified through the regulatory approval process as appropriate. Revenue is recognized over time as the service is rendered to the customer. Included in PSE&G’s regulated revenues are unbilled electric and gas revenues which represent the estimated amount customers will be billed for services rendered from the most recent meter reading to the end of the respective accounting period.

PSE&G’s transmission revenues are earned under a separate tariff using a FERC-approved annual formula rate mechanism. The performance obligation of transmission service is satisfied and revenue is recognized as it is provided to the customer. The formula rate mechanism provides for an annual filing of an estimated revenue requirement with rates effective January 1 of each year and a true-up to that estimate based on actual revenue requirements. The true-up mechanism is an alternative revenue which is outside the scope of revenue from contracts with customers.

Other Revenues from Contracts with Customers

Other revenues from contracts with customers, which are not a material source of PSE&G revenues, are generated primarily from appliance repair services and solar generation projects. The performance obligations under these contracts are satisfied and revenue is recognized as control of products is delivered or services are rendered.

Payment for services rendered and products transferred are typically due within 30 days of month of delivery.

Revenues Unrelated to Contracts with Customers

Other PSE&G revenues unrelated to contracts with customers are derived from alternative revenue mechanisms recorded pursuant to regulatory accounting guidance. These revenues, which include weather normalization, green energy program true-ups and transmission formula rate true-ups, are not a material source of PSE&G revenues.

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PSEG Power

Revenues from Contracts with Customers

Electricity and Related Products—Wholesale and retail load contracts are executed in the different ISO regions for the bundled supply of energy, capacity, renewable energy credits (RECs) and ancillary services representing PSEG Power’s performance obligations. Revenue for these contracts is recognized over time as the bundled service is provided to the customer. Transaction terms generally run from several months to three years. PSEG Power also sells to the ISOs energy and ancillary services which are separately transacted in the day-ahead or real-time energy markets. The energy and ancillary services performance obligations are typically satisfied over time as delivered and revenue is recognized accordingly. PSEG Power generally reports electricity sales and purchases conducted with those individual ISOs net on an hourly basis in either Operating Revenues or Energy Costs in its Consolidated Statements of Operations. The classification depends on the net hourly activity.

PSEG Power enters into capacity sales and capacity purchases through the ISOs. The transactions are reported on a net basis dependent on PSEG Power’s monthly net sale or purchase position through the individual ISOs. The performance obligations with the ISOs are satisfied over time upon delivery of the capacity and revenue is recognized accordingly. In addition to capacity sold through the ISOs, PSEG Power sells capacity through bilateral contracts and the related revenue is reported on a gross basis and recognized over time upon delivery of the capacity.

In April 2019, PSEG Power’s Salem 1, Salem 2 and Hope Creek nuclear plants were awarded Zero Emission Certificates (ZECs) by the BPU. These nuclear plants are expected to receive ZEC revenue for approximately three years, through May 2022 from the electric distribution companies (EDCs) in New Jersey. PSEG Power recognizes revenue when the units generate electricity, which is when the performance obligation is satisfied. These revenues are included in PJM Sales in the following tables. See Note 4. Early Plant Retirements/Asset Dispositions for additional information.

Gas Contracts—PSEG Power sells wholesale natural gas, primarily through an index based full-requirements Basic Gas Supply Service (BGSS) contract with PSE&G to meet the gas supply requirements of PSE&G’s customers. The BGSS contract remains in effect unless terminated by either party with a two-year notice. The performance obligation is primarily delivery of gas which is satisfied over time. Revenue is recognized as gas is delivered. Based upon the availability of natural gas, storage and pipeline capacity beyond PSE&G’s daily needs, PSEG Power also sells gas and pipeline capacity to other counterparties under bilateral contracts. The performance obligation under these contracts is satisfied over time upon delivery of the gas or capacity, and revenue is recognized accordingly.

Other Revenues from Contracts with Customers

PSEG Power enters into bilateral contracts to sell solar power and solar RECs from its solar facilities. Contract terms range from 15 to 30 years. The performance obligations are generally solar power and RECs which are transferred to customers upon generation. Revenue is recognized upon generation of the solar power.

PSEG Power has entered into long-term contracts with LIPA for energy management and fuel procurement services. Revenue is recognized over time as services are rendered.

Revenues Unrelated to Contracts with Customers

PSEG Power’s revenues unrelated to contracts with customers include electric, gas and certain energy-related transactions accounted for in accordance with Derivatives and Hedging accounting guidance. See Note 18. Financial Risk Management Activities for further discussion. PSEG Power is also a party to solar contracts that qualify as leases and are accounted for in accordance with lease accounting guidance.

Other

Revenues from Contracts with Customers

PSEG LI has a contract with LIPA which generates revenues. PSEG LI’s subsidiary, Servco records costs which are recovered from LIPA and records the recovery of those costs as revenues when Servco is a principal in the transaction.

Revenues Unrelated to Contracts with Customers

Energy Holdings generates lease revenues which are recorded pursuant to lease accounting guidance.

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Disaggregation of Revenues




	PSE&G		PSEG Power		Other			Eliminations			Consolidated
	Millions
Year Ended December 31, 2019
Revenues from Contracts with Customers
Electric Distribution	$	3,224	$	—	$	—		$	—		$	3,224
Gas Distribution	1,870		—		—			(15		)	1,855
Transmission	1,181		—		—			—			1,181
Electricity and Related Product Sales
PJM
Third-Party Sales	—		1,785		—			—			1,785
Sales to Affiliates	—		536		—			(536		)	—
NY-ISO	—		143		—			—			143
ISO-NE	—		137		—			—			137
Gas Sales
Third-Party Sales	—		92		—			—			92
Sales to Affiliates	—		927		—			(927		)	—
Other Revenues from Contracts with Customers (A)	284		46		566			(5		)	891
Total Revenues from Contracts with Customers	6,559		3,666		566			(1,483		)	9,308
Revenues Unrelated to Contracts with Customers (B)	66		719		(17		)	—			768
Total Operating Revenues	$	6,625	$	4,385	$	549		$	(1,483	)	$	10,076




	PSE&G		PSEG Power		Other		Eliminations			Consolidated
	Millions
Year Ended December 31, 2018
Revenues from Contracts with Customers
Electric Distribution	$	3,131	$	—	$	—	$	—		$	3,131
Gas Distribution	1,756		—		—		(18		)	1,738
Transmission	1,236		—		—		—			1,236
Electricity and Related Product Sales
PJM
Third-Party Sales	—		1,933		—		—			1,933
Sales to Affiliates	—		609		—		(609		)	—
NY-ISO	—		209		—		—			209
ISO-NE	—		92		—		—			92
Gas Sales
Third-Party Sales	—		151		—		—			151
Sales to Affiliates	—		861		—		(861		)	—
Other Revenues from Contracts with Customers (A)	275		44		532		(4		)	847
Total Revenues from Contracts with Customers	6,398		3,899		532		(1,492		)	9,337
Revenues Unrelated to Contracts with Customers (B)	73		247		39		—			359
Total Operating Revenues	$	6,471	$	4,146	$	571	$	(1,492	)	$	9,696

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	PSE&G		PSEG Power		Other			Eliminations			Consolidated
	Millions
Year Ended December 31, 2017
Revenues from Contracts with Customers
Electric Distribution	$	3,088	$	—	$	—		$	—		$	3,088
Gas Distribution	1,684		—		—			(14		)	1,670
Transmission	1,222		—		—			—			1,222
Electricity and Related Product Sales
PJM
Third-Party Sales	—		1,199		—			—			1,199
Sales to Affiliates	—		734		—			(734		)	—
NY-ISO	—		181		—			—			181
ISO-NE	—		39		—			—			39
Gas Sales
Third-Party Sales	—		134		—			—			134
Sales to Affiliates	—		804		—			(804		)	—
Other Revenues from Contracts with Customers (A)	265		42		511			(4		)	814
Total Revenues from Contracts with Customers	6,259		3,133		511			(1,556		)	8,347
Revenues Unrelated to Contracts with Customers (B)	65		727		(45		)	—			747
Total Operating Revenues	$	6,324	$	3,860	$	466		$	(1,556	)	$	9,094


(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.

Contract Balances

PSE&G

PSE&G did not have any material contract balances (rights to consideration for services already provided or obligations to provide services in the future for consideration already received) as of December 31, 2019 and 2018. Substantially all of PSE&G’s accounts receivable result from contracts with customers that are priced at tariff rates. Allowances represented approximately six percent and seven percent of accounts receivable as of December 31, 2019 and 2018, respectively.

PSEG Power

PSEG Power generally collects consideration upon satisfaction of performance obligations, and therefore, PSEG Power had no material contract balances as of December 31, 2019 and 2018.

PSEG Power’s accounts receivable include amounts resulting from contracts with customers and other contracts which are out of scope of accounting guidance for revenues from contracts with customers. The majority of these accounts receivable are subject to master netting agreements. As a result, accounts receivable resulting from contracts with customers and receivables unrelated to contracts with customers are netted within Accounts Receivable and Accounts Payable on the Consolidated Balance Sheets. In the wholesale energy markets in which PSEG Power operates, payment for services rendered and products transferred are typically due within 30 days of month of delivery. As such, there is little credit risk associated with these receivables and PSEG Power typically records no allowances.

Other

PSEG LI does not have any material contract balances as of December 31, 2019 and 2018.

Remaining Performance Obligations under Fixed Consideration Contracts

PSEG Power and PSE&G primarily record revenues as allowed by the guidance, which states that if an entity has a right to consideration from a customer in an amount that corresponds directly with the value to the customer of the entity's performance completed to date, the entity may recognize revenue in the amount to which the entity has a right to invoice. PSEG has future performance obligations under contracts with fixed consideration as follows:

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PSEG Power

As previously stated, capacity transactions with ISOs are reported on a net basis dependent on PSEG Power’s monthly net sale or purchase position through the individual ISOs.

Capacity Revenues from the PJM Annual Base Residual and Incremental Auctions—The Base Residual Auction is conducted annually three years in advance of the operating period. PSEG Power expects to realize the following average capacity prices resulting from the base and incremental auctions, including unit specific bilateral contracts for previously cleared capacity obligations. These numbers exclude cleared capacity associated with our ownership interests in the Keystone and Conemaugh generation plants that were sold in September 2019. For additional information see Note 4. Early Plant Retirements/Asset Dispositions.




Delivery Year	$ per Megawatt (MW)-Day	MW Cleared
June 2019 to May 2020	$116	8,300
June 2020 to May 2021	$179	7,300
June 2021 to May 2022	$182	6,900

Capacity Payments from the ISO-NE Forward Capacity Market—The Forward Capacity Market (FCM) Auction is conducted annually three years in advance of the operating period. The table below includes PSEG Power’s cleared capacity in the FCM Auction for the Bridgeport Harbor Station 5 (BH5), which cleared the 2019/2020 auction at $231/MW-day for seven years, and the planned retirement of Bridgeport Harbor Station 3 (BH3) in 2021. PSEG Power expects to realize the following average capacity prices for capacity obligations to be satisfied resulting from the FCM auctions which have been completed:




Delivery Year	$ per MW-Day (A)	MW Cleared
June 2019 to May 2020	$231	1,330
June 2020 to May 2021	$195	1,330
June 2021 to May 2022	$192	950
June 2022 to May 2023	$179	950
June 2023 to May 2024	$231	480
June 2024 to May 2025	$231	480
June 2025 to May 2026	$231	480


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

Bilateral capacity contracts—Capacity obligations pursuant to contract terms through 2029 are anticipated to result in revenues totaling $168 million.

Other

The LIPA OSA is a 12-year services contract ending in 2025 with annual fixed and incentive components. The fixed fee for the provision of services thereunder in 2020 is $67 million and could increase each year based on the change in the Consumer Price Index (CPI).

Note 4. Early Plant Retirements/Asset Dispositions

Nuclear

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preventing the retirement of nuclear plants. The BPU’s decision awarding ZECs has been appealed by the Division of Rate Counsel. PSEG cannot predict the outcome of this matter. In the event that (i) the ZEC program is overturned or otherwise materially adversely modified through legal process, (ii) the terms and conditions of the subsequent period under the ZEC program, including the amount of ZEC payments that may be awarded, materially differ from those of the current ZEC period, or (iii) any of the Salem 1, Salem 2 and Hope Creek plants is not awarded ZEC payments by the BPU and does not otherwise experience a material financial change, PSEG Power will take all necessary steps to retire all of these plants subsequent to the initial ZEC period at or prior to a scheduled refueling outage. Alternatively, if all of the Salem 1, Salem 2 and Hope Creek plants are selected to continue to receive ZEC payments but the financial condition of the plants is materially adversely impacted by changes in commodity prices, FERC’s changes to the capacity market construct (absent sufficient capacity revenues provided under a program approved by the BPU in accordance with a FERC-authorized capacity mechanism), or, in the case of the Salem nuclear plants, decisions by the EPA and state environmental regulators regarding the implementation of Section 316(b) of the Clean Water Act and related state regulations, or other factors, PSEG Power would still take all necessary steps to retire all of these plants. The costs and accounting charges associated with any such retirement, which may include, among other things, accelerated D&A, impairment charges, potential penalties associated with the early termination of capacity obligations and fuel contracts, accelerated asset retirement costs, severance costs, environmental remediation costs and, in certain circumstances potential additional funding of the NDT Fund, would be material to both PSEG and PSEG Power.

Fossil

In June 2017, PSEG Power completed its retirement of the generation operations of the existing coal/gas units at the Hudson and Mercer generating stations.

During the year ended December 31, 2017, PSEG Power recognized total D&A of $964 million for the Hudson and Mercer units to reflect the significant shortening of their expected economic useful lives. In December 2018, PSEG Power completed the sale of the sites of the retired Hudson and Mercer units. PSEG Power transferred all land rights and structures on the sites to a third-party purchaser, along with the assumption of the environmental liabilities for the sites. As a result of the sale and transfer of liabilities, PSEG Power recorded a pre-tax gain in 2018 of $54 million.

On February 23, 2020, PSEG Fossil LLC (Fossil), a direct wholly owned subsidiary of PSEG Power, entered into a Purchase Agreement with Yards Creek Energy, LLC (Yards Creek Energy), an affiliate of LS Power, relating to the sale by Fossil of its ownership interests in the Yards Creek generation facility and related assets, including the assumption by Yards Creek Energy of related liabilities. The transaction is targeted to close during the second half of 2020, subject to customary closing conditions and regulatory approvals. As a result, in the fourth quarter of 2019, $28 million of Property, Plant and Equipment was reclassified as Assets Held for Sale on PSEG’s and PSEG Power’s Consolidated Balance Sheets.

Note 5. Variable Interest Entity (VIE)

VIE for which PSEG LI is the Primary Beneficiary

PSEG LI consolidates Servco, a marginally capitalized VIE, which was created for the purpose of operating LIPA’s T&D system in Long Island, New York as well as providing administrative support functions to LIPA. PSEG LI is the primary beneficiary of Servco because it directs the operations of Servco, the activity that most significantly impacts Servco’s economic performance and it has the obligation to absorb losses of Servco that could potentially be significant to Servco. Such losses would be immaterial to PSEG.

Pursuant to the OSA, Servco’s operating costs are reimbursable entirely by LIPA, and therefore, PSEG LI’s risk is limited related to the activities of Servco. PSEG LI has no current obligation to provide direct financial support to Servco. In addition to reimbursement of Servco’s operating costs as provided for in the OSA, PSEG LI receives an annual contract management fee. PSEG LI’s annual contractual management fee, in certain situations, could be partially offset by Servco’s annual storm costs not approved by the Federal Emergency Management Agency, limited contingent liabilities and penalties for failing to meet certain performance metrics.

For transactions in which Servco acts as principal and controls the services provided to LIPA, such as transactions with its employees for labor and labor-related activities, including pension and OPEB-related transactions, Servco records revenues and the related pass-through expenditures separately in Operating Revenues and O&M Expense, respectively. In 2019, 2018 and 2017, Servco recorded $490 million, $458 million and $438 million, respectively, of O&M costs, the full reimbursement of which was reflected in Operating Revenues. For transactions in which Servco acts as an agent for LIPA, it records revenues and the related expenses on a net basis, resulting in no impact on PSEG’s Consolidated Statement of Operations.

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Note 6. Property, Plant and Equipment and Jointly-Owned Facilities

Information related to Property, Plant and Equipment as of December 31, 2019 and 2018 is detailed below:




	PSE&G		PSEG Power		Other		PSEG Consolidated
	Millions
2019
Transmission and Distribution:
Electric Transmission	$	12,908	$	—	$	—	$	12,908
Electric Distribution	9,255		—		—		9,255
Gas Distribution and Transmission	8,430		—		—		8,430
Construction Work in Progress	1,607		—		—		1,607
Other	639		—		—		639
Total Transmission and Distribution	32,839		—		—		32,839
Generation:
Fossil Production	—		6,570		—		6,570
Nuclear Production	—		3,087		—		3,087
Nuclear Fuel in Service	—		761		—		761
Other Production-Solar	663		911		—		1,574
Construction Work in Progress	—		277		—		277
Total Generation	663		11,606		—		12,269
Other	398		93		345		836
Total	$	33,900	$	11,699	$	345	$	45,944




	PSE&G		PSEG Power		Other		PSEG Consolidated
	Millions
2018
Transmission and Distribution:
Electric Transmission	$	11,991	$	—	$	—	$	11,991
Electric Distribution	8,989		—		—		8,989
Gas Distribution and Transmission	7,854		—		—		7,854
Construction Work in Progress	1,170		—		—		1,170
Other	624		—		—		624
Total Transmission and Distribution	30,628		—		—		30,628
Generation:
Fossil Production	—		6,541		—		6,541
Nuclear Production	—		2,971		—		2,971
Nuclear Fuel in Service	—		765		—		765
Other Production-Solar	623		833		—		1,456
Construction Work in Progress	—		1,011		—		1,011
Total Generation	623		12,121		—		12,744
Other	382		103		344		829
Total	$	31,633	$	12,224	$	344	$	44,201

As part of its solar production portfolio, PSEG Power owns and operates two California-based solar facilities with an aggregate capacity of approximately 30 MW direct current whose output is sold to Pacific Gas and Electric Company (PG&E) under power purchase agreements (PPAs) with twenty year terms. The net book value of these solar facilities was approximately $55 million as of December 31, 2019. In January 2019, PG&E and its parent company PG&E Corporation filed for Chapter 11 bankruptcy protection. PSEG Power cannot predict the ultimate outcome that this bankruptcy proceeding will have on its ability to collect all of the future revenues from these facilities due under the PPAs; however, any adverse changes to the terms of

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PSEG Power’s PPAs as a result of this bankruptcy proceeding could result in the future impairment of these assets in amounts up to their current net book value.

PSE&G and PSEG Power have ownership interests in and are responsible for providing their respective shares of the necessary financing for the following jointly-owned facilities to which they are a party. All amounts reflect PSE&G’s or PSEG Power’s share of the jointly-owned projects and the corresponding direct expenses are included in the Consolidated Statements of Operations as Operating Expenses.




			As of December 31,
			2019				2018
	Ownership				Accumulated				Accumulated
	Interest		Plant		Depreciation		Plant		Depreciation
			Millions
PSE&G:
Transmission Facilities	Various		$	161	$	60	$	162	$	58
PSEG Power:
Coal Generating (A):
Conemaugh	23	%	N/A		N/A		$	417	$	192
Keystone	23	%	N/A		N/A		$	416	$	200
Nuclear Generating:
Peach Bottom	50	%	$	1,340	$	435	$	1,334	$	389
Salem	57	%	$	1,256	$	384	$	1,196	$	333
Nuclear Support Facilities	Various		$	247	$	107	$	244	$	95
Pumped Storage Facilities:
Yards Creek (B)	50	%	$	55	$	27	$	48	$	26
Merrill Creek Reservoir	14	%	$	1	$	—	$	1	$	—


(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.

PSEG Power holds undivided ownership interests in the jointly-owned facilities above. PSEG Power is entitled to shares of the generating capability and output of each unit equal to its respective ownership interests. PSEG Power also pays its ownership share of additional construction costs, fuel inventory purchases and operating expenses. PSEG Power’s share of expenses for the jointly-owned facilities is included in the appropriate expense category. Each owner is responsible for any financing with respect to its pro rata share of capital expenditures.

PSEG Power co-owns Salem and Peach Bottom with Exelon Generation. PSEG Power is the operator of Salem and Exelon Generation is the operator of Peach Bottom. A committee appointed by the co-owners provides oversight. Proposed O&M budgets and requests for major capital expenditures are reviewed and approved as part of the normal PSEG Power governance process.

PSEG Power is a co-owner in the Yards Creek Pumped Storage Generation Facility. Jersey Central Power & Light Company (JCP&L) is also a co-owner and the operator of this facility. JCP&L submits separate capital and O&M budgets, subject to PSEG Power’s approval as part of the normal PSEG Power governance process.

PSEG Power is a minority owner in the Merrill Creek Reservoir and Environmental Preserve in Warren County, New Jersey. Merrill Creek Owners Group is the owner-operator of this facility. The operator submits separate capital and O&M budgets, subject to PSEG Power’s approval as part of the normal PSEG Power governance process.

Note 7. Regulatory Assets and Liabilities

PSE&G prepares its financial statements in accordance with GAAP for regulated utilities as described in Note 1. Organization, Basis of Presentation and Significant Accounting Policies. PSE&G has deferred certain costs based on rate orders issued by the BPU or FERC or based on PSE&G’s experience with prior rate proceedings. Most of PSE&G’s Regulatory Assets and Liabilities as of December 31, 2019 are supported by written orders, either explicitly or implicitly through the BPU’s treatment of various cost items. These costs will be recovered and amortized over various future periods.

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Regulatory Assets and other investments and costs incurred under our various infrastructure filings and clause mechanisms are subject to prudence reviews and can be disallowed in the future by regulatory authorities. To the extent that collection of any infrastructure or clause mechanism revenue, Regulatory Assets or payments of Regulatory Liabilities is no longer probable, the amounts would be charged or credited to income.

PSE&G had the following Regulatory Assets and Liabilities:




	As of December 31,
	2019		2018
	Millions
Regulatory Assets
Current
New Jersey Clean Energy Program	$	143	$	143
Electric Energy Costs—Basic Generation Service (BGS)	57		115
2018 Distribution Base Rate Case Regulatory Assets (BRC)	56		56
Societal Benefits Charge (SBC)	30		9
Green Program Recovery Charges (GPRC)	10		34
Other	55		32
Total Current Regulatory Assets	$	351	$	389
Noncurrent
Pension and OPEB Costs	$	1,284	$	1,090
Deferred Income Tax Regulatory Assets	966		896
Manufactured Gas Plant (MGP) Remediation Costs	357		321
Electric Transmission and Gas Cost of Removal	216		223
Asset Retirement Obligation	172		166
BRC	159		214
Remediation Adjustment Charge (RAC) (Other SBC)	158		175
GPRC	118		95
Unamortized Loss on Reacquired Debt and Debt Expense	42		49
Gas Costs—BGSS	27		31
Other	178		139
Total Noncurrent Regulatory Assets	$	3,677	$	3,399
Total Regulatory Assets	$	4,028	$	3,788




	As of December 31,
	2019		2018
	Millions
Regulatory Liabilities
Current
Deferred Income Tax Regulatory Liabilities	$	193	$	299
Weather Normalization Charge (WNC)	15		—
Tax Adjustment Credit (TAC)	12		4
Gas Margin Adjustment Clause	5		8
Other	9		—
Total Current Regulatory Liabilities	$	234	$	311
Noncurrent
Deferred Income Tax Regulatory Liabilities	$	2,955	$	3,170
Electric Distribution Cost of Removal	47		51
Total Noncurrent Regulatory Liabilities	$	3,002	$	3,221
Total Regulatory Liabilities	$	3,236	$	3,532

All Regulatory Assets and Liabilities are excluded from PSE&G’s rate base unless otherwise noted. The Regulatory Assets and Liabilities in the table above are defined as follows:

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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:

•

$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.

In addition, PSE&G agreed to flow back to customers $581 million of previously realized tax repair deductions over a ten-year period through the TAC mechanism. As of December 31, 2019 and 2018, the balance remaining to be flowed back to customers was $537 million and $575 million, respectively.


•	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.

•

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.

•

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.

Significant 2018 and 2019 regulatory orders received and currently pending rate filings with FERC and the BPU by PSE&G are as follows:

•

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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the BPU had approved a rate reduction effective April 1, 2018, to PSE&G’s then-current electric and gas base rates of approximately $71 million and $43 million, respectively, on an annual basis, to reflect the lower federal income tax rate for the period April 1 and forward. As a result of the agreement to flow back tax repair-related accumulated deferred income taxes in the settlement, PSE&G recognized a Regulatory Liability and a corresponding Regulatory Asset.


•	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.

In June 2019, PSE&G filed its 2018 true-up adjustment pertaining to its transmission formula rates in effect for 2018. This filing resulted in an additional revenue requirement adjustment of $52 million more than the 2018 originally filed revenue requirement. PSE&G had previously recognized the majority of the additional revenue requirement in its 2018 Consolidated Statement of Operations.

•

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.

In December 2019, PSE&G filed its second GSMP II cost recovery petition seeking BPU approval to recover in gas base rates an estimated annual revenue increase of $18 million effective June 1, 2020. This increase represents the return of and on investment for GSMP II investments expected to be in service through February 29, 2020. The request will be updated in March 2020 for actual costs.


•	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.

In January 2020, the BPU approved PSE&G’s 2019 GPRC cost recovery petition requesting recovery of approximately $52 million and $11 million in electric and gas revenues, respectively, on an annual basis. This increase was effective February 1, 2020.

In May 2019, the BPU approved PSE&G’s 2018 GPRC cost recovery petition requesting recovery of approximately $65 million and $6 million in electric and gas revenues, respectively, on an annual basis.


•	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.

In August 2019, the BPU approved PSE&G’s RAC 26 filing requesting recovery of approximately $73 million in net MGP remediation expenditures from August 1, 2017 through July 31, 2018.


•	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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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.


•	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.

In March 2019, the BPU approved the final 2018-2019 WNC rates which allowed a net recovery of $14 million to be collected over the 2018-2019 Winter Period. The $14 million net recovery was the result of $9 million of excess revenues from the colder-than-normal 2017-2018 Winter Period offset by $23 million of remaining prior Winter Period undercollection.

•

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.

For the energy year ended May 31, 2019, PSE&G purchased approximately $17 million in ZECs, including interest, from the eligible nuclear plants selected by the BPU. The payment for $17 million was made in August 2019. In addition, there was approximately $0.2 million, including interest, in overcollected revenues which will be refunded to customers pending BPU approval of the refunding mechanism.

Note 8. Leases

As of December 31, 2019, PSEG and its subsidiaries were both a lessee and a lessor in operating leases.

Lessee

PSE&G

PSE&G has operating leases for office space for customer service centers, rooftops and land for its Solar 4 All^® facilities, equipment, vehicles and land for certain electric substations. These leases have remaining lease terms through 2039, some of which include options to extend the leases for up to two five-year terms. Some leases have fixed rent payments that have escalations based on certain indices, such as the CPI. Certain leases contain variable payments.

PSEG Power

PSEG Power has operating leases for buildings, land leases for its solar generating facilities, merchant transmission and equipment. These leases have remaining terms through 2055, some of which include options to extend the leases for up to seven five-year terms and certain other leases which include options to extend the leases for 15 to 20 year terms. Some leases have fixed rent payments that have escalations based on certain indices, such as the CPI. Certain leases contain variable payments.

Other

Services has operating leases for real estate and office equipment. These leases have remaining terms through 2030. Services’ lease for its headquarters, which ends in 2030, includes options to extend for two five-year terms. Energy Holdings has land leases with remaining lease terms through 2027, some of which include options to extend the leases for up to eight five-year terms. Some leases have fixed rent payments that have escalations based on certain indices, such as the CPI. Certain leases contain variable payments.

Operating Lease Costs

The following amounts relate to total operating lease costs, including both amounts recognized in the Consolidated Statements of Operations during the year ended December 31, 2019 and any amounts capitalized as part of the cost of another asset, and the cash flows arising from lease transactions.

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	PSE&G			PSEG Power			Other			Total
	Millions
Operating Lease Costs
Year Ended December 31, 2019
Long-term Lease Costs	$	24		$	13		$	15		$	52
Short-term Lease Costs	14			10			—			24
Variable Lease Costs	2			10			10			22
Total Operating Lease Costs	$	40		$	33		$	25		$	98

Year Ended December 31, 2019
Cash Paid for Amounts Included in the Measurement of Operating Lease Liabilities	$	16		$	11		$	15		$	42

Weighted Average Remaining Lease Term in Years	13			14			10			12
Weighted Average Discount Rate	3.6		%	4.4		%	4.2		%	4.1		%

Operating lease commitments as of December 31, 2018 had the following maturities:




	PSE&G		PSEG Power		Other		Total
	Millions
2019	$	15	$	11	$	15	$	41
2020	11		13		16		40
2021	10		13		16		39
2022	8		14		16		38
2023	8		8		15		31
Thereafter	66		51		105		222
Total Minimum Lease Payments	$	118	$	110	$	183	$	411

Operating lease liabilities as of December 31, 2019 had the following maturities:




	PSE&G		PSEG Power		Other		Total
	Millions
2020	$	15	$	13	$	16	$	44
2021	13		14		16		43
2022	10		14		16		40
2023	9		8		15		32
2024	8		3		15		26
Thereafter	71		48		90		209
Total Minimum Lease Payments	$	126	$	100	$	168	$	394

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The following is a reconciliation of the undiscounted cash flows to the discounted Operating Lease Liabilities recognized on the Consolidated Balance Sheets:




	As of December 31, 2019
	PSE&G			PSEG Power			Other			Total
	Millions
Undiscounted Cash Flows	$	126		$	100		$	168		$	394
Reconciling Amount due to Discount Rate	(27		)	(28		)	(33		)	(88		)
Total Discounted Operating Lease Liabilities	$	99		$	72		$	135		$	306

As of December 31, 2019, the current portions of Operating Lease Liabilities included in Other Current Liabilities were $33 million, $12 million and $10 million for PSEG, PSE&G and PSEG Power, respectively.

Lessor

PSEG Power

Certain of PSEG Power’s sales agreements related to its solar generating plants qualify as operating leases with remaining terms through 2043 with no extension terms. Lease income is based on solar energy generation; therefore, all rental income is variable under these leases. As of December 31, 2019, PSEG Power’s solar generating plants subject to these leases had a total carrying value of $393 million.

Other

Energy Holdings is the lessor in leveraged leases. See Note 9. Long-Term Investments and Note 10. Financing Receivables.

Energy Holdings is the lessor in various operating leases for domestic energy and real estate assets with remaining terms through 2036. As of December 31, 2019, Energy Holdings’ property subject to these leases had a total carrying value of $22 million.

The following is the operating lease income for PSEG Power and Energy Holdings for the year ended December 31, 2019:




	PSEG Power		Energy Holdings		Total
	Millions
Operating Lease Income
Year Ended December 31, 2019
Fixed Lease Income	$	—	$	22	$	22
Variable Lease Income	23		—		23
Total Operating Lease Income	$	23	$	22	$	45

Energy Holdings’ operating leases had the following minimum future fixed lease receipts as of December 31, 2019:




	Millions
2020	$	20
2021	18
2022	17
2023	17
2024	16
Thereafter	172
Total Minimum Future Lease Receipts	$	260

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Note 9. Long-Term Investments

Long-Term Investments as of December 31, 2019 and 2018 included the following:




	As of December 31,
	2019		2018
	Millions
PSE&G
Life Insurance and Supplemental Benefits	$	111	$	121
Solar Loans	137		149
PSEG Power
Equity Method Investments (A)	66		86
Energy Holdings
Lease Investments	497		540
Equity Method Investments	1		—
Total Long-Term Investments	$	812	$	896


(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.

Leases

Energy Holdings, through several of its indirect subsidiary companies, has investments in domestic energy and real estate assets subject primarily to leveraged lease accounting. A leveraged lease is typically comprised of an investment by an equity investor and debt provided by a third-party debt investor. The debt is recourse only to the assets subject to lease and is not included on PSEG’s Consolidated Balance Sheets. As an equity investor, Energy Holdings’ equity investments in the leases are comprised of the total expected lease receivables over the lease terms plus the estimated residual values at the end of the lease terms, reduced for any income not yet earned on the leases. This amount is included in Long-Term Investments on PSEG’s Consolidated Balance Sheets. The more rapid depreciation of the leased property for tax purposes creates tax cash flow that will be repaid to the taxing authority in later periods. As such, the liability for such taxes due is recorded in Deferred Income Taxes on PSEG’s Consolidated Balance Sheets.

During the second quarter of 2019, Energy Holdings completed its annual review of estimated residual values embedded in the leveraged leases. The outcome indicated that the updated residual value estimate of the coal-fired Powerton lease was lower than the recorded residual value and the decline was deemed to be other than temporary as a result of expected future adverse market conditions. As a result, a pre-tax write-down of $58 million was reflected in Operating Revenues in 2019, calculated by comparing the gross investment in the leases before and after the revised residual estimates.

In the first quarter of 2020, PSEG’s Board of Directors approved the marketing and sale of certain non-core assets held by subsidiaries of Energy Holdings. As a result, PSEG expects to reclassify approximately $160 million as Assets Held for Sale on its Consolidated Balance Sheet in the first quarter of 2020.

Due to liquidity issues facing NRG REMA, LLC (REMA) prior to its emergence from bankruptcy protection, economic challenges facing coal generation in PJM and based upon ongoing reviews of available alternatives as well as certain discussions with REMA management leading up to and in connection with REMA’s bankruptcy, Energy Holdings recorded pre-tax charges of $20 million in 2018 and $77 million (including a residual value impairment of $7 million) in 2017. Pre-tax charges were reflected in Operating Revenues in each year and are included in Gross Investment in Leases as of December 31, 2019.

In December 2018, REMA emerged from its in-court proceeding under Chapter 11 of the Bankruptcy Code. As a result of the restructuring, Energy Holdings recognized a pre-tax gain in Operating Revenues of approximately $12 million ($9 million after tax). PSEG realized the remaining tax liability related to the restructuring of approximately $120 million with the filing of the consolidated federal and state income tax returns in 2019.

The following table shows Energy Holdings’ gross and net lease investment as of December 31, 2019 and 2018.

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	As of December 31,
	2019			2018
	Millions
Lease Receivables (net of Non-Recourse Debt)	$	498		$	504
Estimated Residual Value of Leased Assets	202			326
Total Investment in Rental Receivables	700			830
Unearned and Deferred Income	(203		)	(290		)
Gross Investments in Leases	497			540
Deferred Tax Liabilities	(328		)	(354		)
Net Investments in Leases	$	169		$	186

The pre-tax income (loss) and income tax effects related to investments in leases, excluding gains and losses on sales and the impacts of the Tax Act, were as follows:




	Years Ended December 31,
	2019			2018		2017
	Millions
Pre-Tax Income (Loss) from Leases	$	(39	)	$	17	$	(69	)
Income Tax Expense (Benefit) on Income from Leases	$	(22	)	$	6	$	(26	)

Equity Method Investments

PSEG Power had the following equity method investments as of December 31, 2019 and 2018:




	As of December 31,
Name	2019		2018		Location	% Owned
	Millions
PSEG Power
Keystone Fuels, LLC (A)	$	—	$	9	PA	23%
Conemaugh Fuels, LLC (A)	—		8		PA	23%
Kalaeloa	66		69		HI	50%
Total	$	66	$	86


(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.

Note 10. Financing Receivables

PSE&G

PSE&G sponsors a solar loan program designed to help finance the installation of solar power systems throughout its electric service area. Interest income on the loans is recorded on an accrual basis. The loans are generally paid back with solar renewable energy certificates generated from the installed solar electric system. In the event of a loan default, the basis of the solar loan would be recovered through a regulatory recovery mechanism. None of the solar loans are impaired; however, in the event a loan becomes impaired, the basis of the loan would be recovered through a regulatory recovery mechanism. A substantial portion of these amounts are noncurrent and reported in Long-Term Investments on PSEG’s and PSE&G’s Consolidated Balance Sheets. The following table reflects the outstanding loans by class of customer, none of which would be considered “non-performing.”

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Outstanding Loans by Class of Customer
	As of December 31,
Consumer Loans	2019			2018
	Millions
Commercial/Industrial	$	156		$	164
Residential	8			9
Total	$	164		$	173
Current Portion (included in Accounts Receivable)	(28		)	(24		)
Noncurrent Portion (included in Long-Term Investments)	$	136		$	149

Energy Holdings

Energy Holdings had a net investment in domestic energy and real estate assets subject to leveraged lease accounting of $169 million as of December 31, 2019 and $186 million as of December 31, 2018 (See Note 9. Long-Term Investments).

The corresponding receivables associated with the lease portfolio are reflected as follows, net of non-recourse debt. The ratings in the table represent the ratings of the entities providing payment assurance to Energy Holdings.




	Lease Receivables, Net of Non-Recourse Debt
Counterparties’ Credit Rating Standard & Poor’s (S&P) as of December 31, 2019	As of December 31, 2019
	Millions
AA	$	12
A-	58
BBB+ — BBB	258
BB	132
NR	38
Total	$	498

The “BB” and the “NR” ratings in the preceding table represent lease receivables related to coal and gas-fired assets in Illinois and Pennsylvania, respectively. As of December 31, 2019, the gross investment in the leases of such assets, net of non-recourse debt, was $235 million ($(22) million, net of deferred taxes). A more detailed description of such assets under lease follows:

Asset

Location

Gross

Investment

Owned

Total MW

Fuel

Type

Counterparties’

S&P Credit

Ratings

Counterparty

Millions

Powerton Station Units 5 and 6

1,538

Coal

NRG Energy, Inc.

Joliet Station Units 7 and 8

1,036

Gas

NRG Energy, Inc.

Shawville Station Units 1, 2, 3 and 4

100

596

Gas

REMA (A)


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

The credit exposure for lessors is partially mitigated through various credit enhancement mechanisms within the lease structures. These credit enhancement features vary from lease to lease. Upon the occurrence of certain defaults, indirect subsidiary companies of Energy Holdings would exercise their rights and seek recovery of their investment, potentially including stepping into the lease directly to protect their investments. While these actions could ultimately protect or mitigate the loss of value, they could require the use of significant capital and trigger certain material tax obligations which could, for certain leases, wholly or partially be mitigated by tax indemnification claims against the counterparty. A bankruptcy of a lessee would likely delay and potentially limit any efforts on the part of the lessors to assert their rights upon default and could delay the monetization of claims.

Additional factors that may impact future lease cash flows include, but are not limited to, new environmental legislation and regulation regarding air quality, water and other discharges in the process of generating electricity, market prices for fuel,

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electricity and capacity, overall financial condition of lease counterparties and their affiliates and the quality and condition of assets under lease.

Note 11. Trust Investments

NDT Fund

In accordance with NRC regulations, entities owning an interest in nuclear generating facilities are required to determine the costs and funding methods necessary to decommission such facilities upon termination of operation. As a general practice, each nuclear owner places funds in independent external trust accounts it maintains to provide for decommissioning. PSEG Power is required to file periodic reports with the NRC demonstrating that its NDT Fund meets the formula-based minimum NRC funding requirements. PSEG Power maintains an external master NDT to fund its share of decommissioning costs for its five nuclear facilities upon their respective termination of operation. The trust contains two separate funds: a qualified fund and a non-qualified fund. Section 468A of the Internal Revenue Code limits the amount of money that can be contributed into a qualified fund. PSEG Power’s share of decommissioning costs related to its five nuclear units was estimated to be between $2.8 billion and $3.0 billion, including contingencies. The liability for decommissioning recorded on a discounted basis as of December 31, 2019 was approximately $740 million and is included in the Asset Retirement Obligation. The funds are managed by third-party investment managers who operate under investment guidelines developed by PSEG Power.

The following tables show the fair values and gross unrealized gains and losses for the securities held in the NDT Fund.




	As of December 31, 2019
	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	Millions
Equity Securities
Domestic	$	425	$	238	$	(4	)	$	659
International	400		103		(11		)	492
Total Equity Securities	825		341		(15		)	1,151
Available-for-Sale Debt Securities
Government	563		16		(2		)	577
Corporate	470		17		(1		)	486
Total Available-for-Sale Debt Securities	1,033		33		(3		)	1,063
Total NDT Fund Investments (A)	$	1,858	$	374	$	(18	)	$	2,214

(A) The NDT Fund Investments table excludes foreign currency of $2 million as of December 31, 2019,

which is part of the NDT Fund.




	As of December 31, 2018
	Cost		Gross Unrealized Gains			Gross Unrealized Losses			Fair Value
	Millions
Equity Securities
Domestic	$	447	$	153		$	(29	)	$	571
International	323		36		—	(30		)	329
Total Equity Securities	770		189			(59		)	900
Available-for-Sale Debt Securities
Government	498		2			(9		)	491
Corporate	501		1			(15		)	487
Total Available-for-Sale Debt Securities	999		3			(24		)	978
Total NDT Fund Investments	$	1,769	$	192		$	(83	)	$	1,878

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Net unrealized gains (losses) on debt securities of $17 million (after-tax) were included in Accumulated Other Comprehensive Loss on PSEG’s and PSEG Power’s Consolidated Balance Sheets as of December 31, 2019. The portion of net unrealized gains (losses) recognized during 2019 related to equity securities still held at the end of December 31, 2019 was $194 million.

The amounts in the preceding tables do not include receivables and payables for NDT Fund transactions which have not settled at the end of each period. Such amounts are included in Accounts Receivable and Accounts Payable on the Consolidated Balance Sheets as shown in the following table.




	As of December 31,
	2019		2018
	Millions
Accounts Receivable	$	11	$	17
Accounts Payable	$	11	$	5

The following table shows the value of securities in the NDT Fund that have been in an unrealized loss position for less than and greater than 12 months.




	As of December 31, 2019										As of December 31, 2018
	Less Than 12 Months					Greater Than 12 Months					Less Than 12 Months					Greater Than 12 Months
	Fair Value		Gross Unrealized Losses			Fair Value		Gross Unrealized Losses			Fair Value		Gross Unrealized Losses			Fair Value		Gross Unrealized Losses
	Millions
Equity Securities (A)
Domestic	$	21	$	(1	)	$	6	$	(3	)	$	147	$	(26	)	$	5	$	(3	)
International	28		(2		)	34		(9		)	131		(28		)	5		(2		)
Total Equity Securities	49		(3		)	40		(12		)	278		(54		)	10		(5		)
Available-for-Sale Debt Securities
Government (B)	99		(2		)	30		—			51		—			317		(9		)
Corporate (C)	49		—			12		(1		)	150		(5		)	222		(10		)
Total Available-for-Sale Debt Securities	148		(2		)	42		(1		)	201		(5		)	539		(19		)
NDT Trust Investments	$	197	$	(5	)	$	82	$	(13	)	$	479	$	(59	)	$	549	$	(24	)


(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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The proceeds from the sales of and the net gains (losses) on securities in the NDT Fund were:




	Years Ended December 31,
	2019			2018			2017
	Millions
Proceeds from Sales (A)	$	1,614		$	1,398		$	2,137
Net Realized Gains (Losses):
Gross Realized Gains	$	107		$	121		$	157
Gross Realized Losses	(53		)	(51		)	(23		)
Net Realized Gains (Losses) on NDT Fund (B)	54			70			134
Unrealized Gains (Losses) on Equity Securities in NDT Fund (C)	196			(209		)	N/A
Other-Than-Temporary-Impairments (OTTI)	—			—			(12		)
Net Gains (Losses) on NDT Fund Investments	$	250		$	(139	)	$	122


(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).

The NDT Fund debt securities held as of December 31, 2019 had the following maturities:




Time Frame	Fair Value
	Millions
Less than one year	$	19
1 - 5 years	273
6 - 10 years	188
11 - 15 years	51
16 - 20 years	77
Over 20 years	455
Total NDT Available-for-Sale Debt Securities	$	1,063

PSEG Power periodically assesses individual debt securities whose fair value is less than amortized cost to determine whether the investments are considered to be other-than-temporarily impaired. For these securities, management considers its intent to sell or requirement to sell a security prior to expected recovery. In those cases where a sale is expected, any impairment would be recorded through earnings. For fixed income securities where there is no intent to sell or likely requirement to sell, management evaluates whether credit loss is a component of the impairment. If so, that portion is recorded through earnings while the noncredit loss component is recorded through Accumulated Other Comprehensive Income (Loss). Any subsequent recoveries in the value of these securities would be recognized in Accumulated Other Comprehensive Income (Loss) unless the securities are sold, in which case, any gain would be recognized in income. The assessment of fair market value compared to cost is applied on a weighted average basis taking into account various purchase dates and initial cost of the securities.

Rabbi Trust

PSEG maintains certain unfunded nonqualified benefit plans to provide supplemental retirement and deferred compensation benefits to certain key employees. Certain assets related to these plans have been set aside in a grantor trust commonly known as a “Rabbi Trust.”

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The following tables show the fair values, gross unrealized gains and losses and amortized cost basis for the securities held in the Rabbi Trust.




	As of December 31, 2019
	Cost		Gross Unrealized Gains		Gross Unrealized Losses		Fair Value
	Millions
Equity Securities
Domestic	$	21	$	7	$	—	$	28
International	—		—		—		—
Total Equity Securities	21		7		—		28
Available-for-Sale Debt Securities
Government	100		4		—		104
Corporate	107		7		—		114
Total Available-for-Sale Debt Securities	207		11		—		218
Total Rabbi Trust Investments	$	228	$	18	$	—	$	246




	As of December 31, 2018
	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	Millions
Equity Securities
Domestic	$	22	$	1	$	—		$	23
International	—		—		—			—
Total Equity Securities	22		1		—			23
Available-for-Sale Debt Securities
Government	110		1		(2		)	109
Corporate	96		—		(4		)	92
Total Available-for-Sale Debt Securities	206		1		(6		)	201
Total Rabbi Trust Investments	$	228	$	2	$	(6	)	$	224

Net unrealized gains (losses) on debt securities of $8 million (after-tax) were included in Accumulated Other Comprehensive Loss on PSEG’s Consolidated Balance Sheet as of December 31, 2019. The portion of net unrealized gains (losses) recognized during 2019 related to equity securities still held at the end of December 31, 2019 was $6 million.

The amounts in the preceding tables do not include receivables and payables for Rabbi Trust Fund transactions which have not settled at the end of each period. Such amounts are included in Accounts Receivable and Accounts Payable on the Consolidated Balance Sheets as shown in the following table.




	As of December 31,
	2019		2018
	Millions
Accounts Receivable	$	2	$	2
Accounts Payable	$	—	$	—

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The following table shows the value of securities in the Rabbi Trust Fund that have been in an unrealized loss position for less than and greater than 12 months:




	As of December 31, 2019								As of December 31, 2018
	Less Than 12 Months				Greater Than 12 Months				Less Than 12 Months					Greater Than 12 Months
	Fair Value		Gross Unrealized Losses		Fair Value		Gross Unrealized Losses		Fair Value		Gross Unrealized Losses			Fair Value		Gross Unrealized Losses
	Millions
Available-for-Sale Debt Securities
Government (A)	$	26	$	—	$	3	$	—	$	18	$	—		$	59	$	(2	)
Corporate (B)	11		—		2		—		50		(3		)	29		(1		)
Total Available-for-Sale Debt Securities	37		—		5		—		68		(3		)	88		(3		)
Rabbi Trust Investments	$	37	$	—	$	5	$	—	$	68	$	(3	)	$	88	$	(3	)

(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.

The proceeds from the sales of and the net gains (losses) on securities in the Rabbi Trust Fund were:




	Years Ended December 31,
	2019			2018			2017
	Millions
Proceeds from Rabbi Trust Sales (A)	$	173		$	103		$	182
Net Realized Gains (Losses):
Gross Realized Gains	$	7		$	2		$	17
Gross Realized Losses	(3		)	(4		)	(5		)
Net Realized Gains (Losses) on Rabbi Trust (B)	4			(2		)	12
Unrealized Gains (Losses) on Equity Securities in Rabbi Trust (C)	6			(2		)	N/A
Net Gains (Losses) on Rabbi Trust Investments	$	10		$	(4	)	$	12


(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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The Rabbi Trust debt securities held as of December 31, 2019 had the following maturities:




Time Frame	Fair Value
	Millions
Less than one year	$	3
1 - 5 years	28
6 - 10 years	33
11 - 15 years	14
16 - 20 years	28
Over 20 years	112
Total Rabbi Trust Available-for-Sale Debt Securities	$	218

PSEG periodically assesses individual debt securities whose fair value is less than amortized cost to determine whether the investments are considered to be other-than-temporarily impaired. For these securities, management considers its intent to sell or requirement to sell a security prior to expected recovery. In those cases where a sale is expected, any impairment would be recorded through earnings. For fixed income securities where there is no intent to sell or likely requirement to sell, management evaluates whether credit loss is a component of the impairment. If so, that portion is recorded through earnings while the noncredit loss component is recorded through Accumulated Other Comprehensive Income (Loss). The assessment of fair market value compared to cost is applied on a weighted average basis taking into account various purchase dates and initial cost of the securities. The fair value of the Rabbi Trust related to PSEG, PSE&G and PSEG Power are detailed as follows:




	As of December 31,		As of December 31,
	2019		2018
	Millions
PSE&G	$	48	$	45
PSEG Power	62		56
Other	136		123
Total Rabbi Trust Investments	$	246	$	224

Note 12. Goodwill and Other Intangibles

As of December 31, 2018, PSEG Power had goodwill of $16 million. PSEG Power conducts a review for goodwill impairment in the fourth quarter of each year. In 2019, PSEG Power determined its fair value using a market-based enterprise valuation technique. Based on the results of the annual impairment test, PSEG Power’s entire goodwill was determined to be impaired. As such, PSEG Power recorded an impairment loss of $16 million in O&M Expense. The decrease in the fair value was primarily due to the continued decline in wholesale power market pricing.

In addition to goodwill, as of December 31, 2019 and 2018, PSEG Power had intangible assets of $149 million and $143 million, respectively, related to emissions allowances and RECs. Emissions allowances and RECs are recorded at cost and evaluated for impairment at least annually. Emissions expense includes impairments of emissions allowances, if any, and costs for emissions, which is recorded as emissions occur. As load is served under contracts requiring energy from renewable sources, the related expense is recorded. The changes to PSEG Power’s intangible assets during 2018 and 2019 are as follows:




	Emissions Allowances			RECs			Total Other Intangibles
	Millions
Balance as of January 1, 2018	$	74		$	40		$	114
Retirements	(26		)	(90		)	(116		)
Purchases	36			110			146
Sales and Transfers, net	—			(1		)	(1		)
Balance as of December 31, 2018	$	84		$	59		$	143
Retirements	(6		)	(83		)	(89		)
Purchases	26			72			98
Sales and Transfers, net	—			(3		)	(3		)
Balance as of December 31, 2019	$	104		$	45		$	149

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Note 13. Asset Retirement Obligations (AROs)

PSEG, PSE&G and PSEG Power recognize liabilities for the expected cost of retiring long-lived assets for which a legal obligation exists to remove or dispose of an asset or some component of an asset at retirement. These AROs are recorded at fair value in the period in which they are incurred and are capitalized as part of the carrying amount of the related long-lived assets. PSE&G, as a rate-regulated entity, recognizes Regulatory Assets or Liabilities as a result of timing differences between the recording of costs and costs recovered through the rate-making process. We accrete the ARO liability to reflect the passage of time with the corresponding expense recorded in O&M.

PSE&G has conditional AROs primarily for legal obligations related to the removal of treated wood poles and the requirement to seal natural gas pipelines at all sources of gas when the pipelines are no longer in service. PSE&G does not record an ARO for its protected steel and poly-based natural gas lines, as management believes that these categories of gas lines have an indeterminable life.

PSEG Power’s ARO liability primarily relates to the decommissioning of its nuclear power plants in accordance with NRC requirements. PSEG Power has an independent external trust that is intended to fund decommissioning of its nuclear facilities upon termination of operation. For additional information, see Note 11. Trust Investments. PSEG Power also identified conditional AROs primarily related to PSEG Power’s fossil generation units and solar facilities, including liabilities for removal of asbestos, ash ponds, stored hazardous liquid material and underground storage tanks from industrial power sites, and demolition of certain plants, and the restoration of the sites at which they reside, when the plants are no longer in service. To estimate the fair value of its AROs, PSEG Power uses a probability weighted, discounted cash flow model which, on a unit by unit basis, considers multiple outcome scenarios that include significant estimates and assumptions, and are based on third-party decommissioning cost estimates, cost escalation rates, inflation rates and discount rates.

Updated cost studies are obtained triennially unless new information necessitates more frequent updates. The most recent cost study was done in 2018. When assumptions are revised to calculate fair values of existing AROs, generally, the ARO balance and corresponding long-lived asset are adjusted which impact the amount of accretion and depreciation expense recognized in future periods. For PSE&G, Regulatory Assets and Regulatory Liabilities result when accretion and amortization are adjusted to match rates established by regulators resulting in the regulatory deferral of any gain or loss.

The changes to the ARO liabilities for PSEG, PSE&G and PSEG Power during 2018 and 2019 are presented in the following table:




	PSEG			PSE&G			PSEG Power			Other
	Millions
ARO Liability as of January 1, 2018	$	1,024		$	212		$	810		$	2
Liabilities Settled	(10		)	(9		)	(1		)	—
Liabilities Incurred	1			—			1			—
Accretion Expense	41			—			41			—
Accretion Expense Deferred and Recovered in Rate Base (A)	12			12			—			—
Revision to Present Values of Estimated Cash Flows	(5		)	87			(93		)	1
ARO Liability as of December 31, 2018	$	1,063		$	302		$	758		$	3
Liabilities Settled	(19		)	(18		)	(1		)	—
Liabilities Incurred	3			1			2			—
Accretion Expense	40			—			40			—
Accretion Expense Deferred and Recovered in Rate Base (A)	16			16			—			—
Revision to Present Values of Estimated Cash Flows	(16		)	2			(18		)	—
ARO Liability as of December 31, 2019	$	1,087		$	303		$	781		$	3


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

In 2019, PSEG Power’s decrease of $18 million was primarily due to the sale of its interests in the Keystone and Conemaugh units. These changes had an immaterial impact in PSEG Power’s Consolidated Statement of Operations. See Note 4. Early Plant Retirements/Asset Dispositions for additional information. In addition, PSEG Power reviewed its probabilities of early retirement on its nuclear units and concluded that no adjustments were necessary as of December 31, 2019.

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In 2018, PSE&G’s increase of $87 million was primarily due to the impact of an increase in labor rates. These changes had no impact in PSE&G’s Consolidated Statement of Operations.

In 2018, PSEG Power’s decrease of $93 million was primarily due to changes in discount rates and decommissioning assumptions related to nuclear. The changes in decommissioning assumptions, including a reduction for the lower probability of early retirement of the nuclear units, were due in part to the enactment of the New Jersey ZEC legislation in May 2018 and that the Salem and Hope Creek Units were the sole applicants under the ZEC program. This reduction was also due to the sale of the Hudson and Mercer units, partially offset by increases in estimated costs to decommission PSEG Power’s fossil units pursuant to its most recent cost study.

Note 14. Pension, Other Postretirement Benefits (OPEB) and Savings Plans

PSEG sponsors qualified and nonqualified pension plans and OPEB plans covering PSEG’s and its participating affiliates’ current and former employees who meet certain eligibility criteria. Eligible employees participate in non-contributory pension and OPEB plans sponsored by PSEG and administered by Services. In addition, represented and nonrepresented employees are eligible for participation in PSEG’s two defined contribution plans described below.

PSEG, PSE&G and PSEG Power are required to record the under or over funded positions of their defined benefit pension and OPEB plans on their respective balance sheets. Such funding positions of each PSEG company are required to be measured as of the date of its respective year-end Consolidated Balance Sheets. For underfunded plans, the liability is equal to the difference between the plan’s benefit obligation and the fair value of plan assets. For defined benefit pension plans, the benefit obligation is the projected benefit obligation. For OPEB plans, the benefit obligation is the accumulated postretirement benefit obligation. In addition, GAAP requires that the total unrecognized costs for defined benefit pension and OPEB plans be recorded as an after-tax charge to Accumulated Other Comprehensive Income (Loss), a separate component of Stockholders’ Equity. However, for PSE&G, because the amortization of the unrecognized costs is being collected from customers, the accumulated unrecognized costs are recorded as a Regulatory Asset. The unrecognized costs represent actuarial gains or losses and prior service costs which had not been expensed.

For PSE&G, the Regulatory Asset is amortized and recorded as net periodic pension cost in the Consolidated Statements of Operations. For PSEG Power, the charge to Accumulated Other Comprehensive Income (Loss) is amortized and recorded as net periodic pension cost in the Consolidated Statements of Operations.

In late June 2019, PSEG approved a plan amendment to its qualified pension plan, effective July 1, 2019. The amendment involved the spin-off of predominantly active participants from the existing qualified pension plan (Pension Plan) into a new qualified pension plan (Pension Plan II). Benefits offered to the plan participants remain unchanged. The existing plan’s pension benefit obligations, as well as the asset values, were remeasured as of July 1, 2019 as a result of the amendment. As of July 1, 2019, the weighted average discount rate for the combined plans decreased from 4.41% to 3.65% and the expected long-term rate of return on plan assets remained at 7.80%. Actuarial gains and losses associated with the Pension Plan will be amortized over the average remaining life expectancy of the inactive participants (as opposed to the average remaining service of active participants prior to the plan being split). Actuarial gains and losses associated with Pension Plan II will be amortized over the average remaining service of active participants. The combined remeasured qualified pension plans’ projected benefit obligation as of July 1, 2019 was $6.4 billion.

In December 2018, PSEG amended certain provisions of its OPEB plans applicable to all current and future Medicare-eligible retirees and spouses who receive or will receive subsidized healthcare from PSEG. Effective January 1, 2021, the PSEG-sponsored Medicare-eligible plans will be replaced by a Medicare private exchange. For each Medicare-eligible retiree and spouse, PSEG will provide annual credits to a Health Reimbursement Arrangement, which can be used to pay for medical, prescription drug, and dental plan premiums, as well as certain out-of-pocket costs. The amendment resulted in a $559 million reduction in PSEG’s OPEB obligation as of December 31, 2018.

Amounts for Servco are not included in any of the following pension and OPEB benefit information for PSEG and its affiliates but rather are separately disclosed later in this note.

The following table provides a roll-forward of the changes in the benefit obligation and the fair value of plan assets during each of the two years in the periods ended December 31, 2019 and 2018. It also provides the funded status of the plans and the amounts recognized and amounts not recognized on the Consolidated Balance Sheets at the end of both years.

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	Pension Benefits						Other Benefits
	2019			2018			2019			2018
	Millions
Change in Benefit Obligation
Benefit Obligation at Beginning of Year (A)	$	5,921		$	6,359		$	1,203		$	1,976
Service Cost	123			130			10			18
Interest Cost	218			208			45			66
Actuarial (Gain) Loss	955			(460		)	109			(222		)
Gross Benefits Paid	(325		)	(316		)	(82		)	(76		)
Plan Amendments	—			—			—			(559		)
Benefit Obligation at End of Year (A)	$	6,892		$	5,921		$	1,285		$	1,203
Change in Plan Assets
Fair Value of Assets at Beginning of Year	$	5,120		$	5,812		$	488		$	511
Actual Return on Plan Assets	1,122			(388		)	107			(36		)
Employer Contributions	12			12			27			89
Gross Benefits Paid	(325		)	(316		)	(82		)	(76		)
Fair Value of Assets at End of Year	$	5,929		$	5,120		$	540		$	488
Funded Status
Funded Status (Plan Assets less Benefit Obligation)	$	(963	)	$	(801	)	$	(745	)	$	(715	)
Additional Amounts Recognized in the Consolidated Balance Sheets
Current Accrued Benefit Cost	$	(11	)	$	(10	)	$	(11	)	$	(11	)
Noncurrent Accrued Benefit Cost	(952		)	(791		)	(734		)	(704		)
Amounts Recognized	$	(963	)	$	(801	)	$	(745	)	$	(715	)
Additional Amounts Recognized in Accumulated Other Comprehensive Income (Loss), Regulated Assets and Deferred Assets (B)
Prior Service Credit	$	(10	)	$	(28	)	$	(433	)	$	(561	)
Net Actuarial Loss	2,150			2,005			409			420
Total	$	2,140		$	1,977		$	(24	)	$	(141	)


(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.

The pension benefits table above provides information relating to the funded status of the qualified and nonqualified pension and OPEB plans on an aggregate basis. As of December 31, 2019, PSEG had funded approximately 86% of its projected pension benefit obligation. This percentage does not include $246 million of assets in the Rabbi Trust as of December 31, 2019 which were used partially to fund the nonqualified pension plans. As of December 31, 2019, the nonqualified pension plans included in the projected benefit obligation in the above table were $176 million.

Accumulated Benefit Obligation

The accumulated benefit obligation for all PSEG’s defined benefit pension plans was $6.7 billion as of December 31, 2019 and $5.7 billion as of December 31, 2018.

The following table provides the components of net periodic benefit cost relating to all qualified and nonqualified pension and OPEB plans on an aggregate basis for PSEG, excluding Servco for the years ended December 31, 2019, 2018 and 2017. Amounts shown do not reflect the impacts of capitalization and co-owner allocations. Effective with the adoption of ASU 2017-07 on January 1, 2018, only the service cost component is eligible for capitalization, when applicable.

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	Pension Benefits Years Ended December 31,									Other Benefits Years Ended December 31,
	2019			2018			2017			2019			2018			2017
	Millions
Components of Net Periodic Benefit (Credits) Costs
Service Cost (included in O&M Expense)	$	123		$	130		$	114		$	10		$	18		$	17
Non-Service Components of Pension and OPEB (Credits) Costs
Interest Cost	218			208			204			45			66			63
Expected Return on Plan Assets	(408		)	(441		)	(394		)	(36		)	(41		)	(34		)
Amortization of Net
Prior Service Credit	(18		)	(18		)	(18		)	(128		)	(1		)	(11		)
Actuarial Loss	96			85			97			50			64			51
Non-Service Components of Pension and OPEB (Credits) Costs	(112		)	(166		)	(111		)	(69		)	88			69
Total Benefit (Credits) Costs	$	11		$	(36	)	$	3		$	(59	)	$	106		$	86

Pension costs and OPEB costs for PSEG, PSE&G and PSEG Power are detailed as follows:




	Pension Benefits Years Ended December 31,								Other Benefits Years Ended December 31,
	2019		2018			2017			2019			2018		2017
	Millions
PSE&G	$	—	$	(31	)	$	(4	)	$	(62	)	$	68	$	54
PSEG Power	4		(9		)	1			3			32		27
Other	7		4			6			—			6		5
Total Benefit (Credits) Costs	$	11	$	(36	)	$	3		$	(59	)	$	106	$	86

The following table provides the pre-tax changes recognized in Accumulated Other Comprehensive Income (Loss), Regulatory Assets and Deferred Assets:




	Pension						OPEB
	2019			2018			2019			2018
	Millions
Net Actuarial (Gain) Loss in Current Period	$	241		$	369		$	39		$	(145	)
Amortization of Net Actuarial Gain (Loss)	(96		)	(85		)	(50		)	(64		)
Prior Service Cost (Credit) in current period	—			—			—			(559		)
Amortization of Prior Service Credit	18			18			128			1
Total	$	163		$	302		$	117		$	(767	)

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Amounts that are expected to be amortized from Accumulated Other Comprehensive Loss, Regulatory Assets and Deferred Assets into Net Periodic Benefit Cost in 2020 are as follows:




	Pension Benefits			Other Benefits
	2020			2020
	Millions
Actuarial Loss	$	92		$	47
Prior Service Credit	$	(10	)	$	(128	)

The following assumptions were used to determine the benefit obligations and net periodic benefit costs:




	Pension Benefits						Other Benefits
	2019		2018		2017		2019			2018			2017
Weighted-Average Assumptions Used to Determine Benefit Obligations as of December 31
Discount Rate	3.30	%	4.41	%	3.73	%	3.20		%	4.31		%	3.76		%
Rate of Compensation Increase	3.90	%	3.90	%	3.90	%	3.90		%	3.90		%	3.90		%
Weighted-Average Assumptions Used to Determine Net Periodic Benefit Cost for Years Ended December 31
Discount Rate	4.41	%	3.73	%	4.29	%	4.31		%	3.76		%	4.37		%
Service Cost Interest Rate	4.58	%	3.88	%	4.53	%	4.48		%	3.90		%	4.64		%
Interest Cost Interest Rate	4.03	%	3.35	%	3.63	%	3.91		%	3.39		%	3.69		%
Expected Return on Plan Assets	7.80	%	7.80	%	7.80	%	7.79		%	7.80		%	7.80		%
Rate of Compensation Increase	3.90	%	3.90	%	3.61	%	3.90		%	3.90		%	3.61		%
Assumed Health Care Cost Trend Rates as of December 31
Health Care Costs
Immediate Rate							6.68		%	7.28		%	7.93		%
Ultimate Rate							4.75		%	4.75		%	4.75		%
Year Ultimate Rate Reached							2029			2026			2026
							Millions
Effect of a 1% Increase in the Assumed Rate of Increase in Health Care Benefit Costs
Total of Service Cost and Interest Cost							$	1		$	1		$	13
Postretirement Benefit Obligation							$	20		$	21		$	240
Effect of a 1% Decrease in the Assumed Rate of Increase in Health Care Benefit Costs
Total of Service Cost and Interest Cost							$	(1	)	$	(1	)	$	(10	)
Postretirement Benefit Obligation							$	(18	)	$	(20	)	$	(198	)

Plan Assets

The investments of pension and OPEB plans are held in a trust account by the Trustee and consist of an undivided interest in an investment account of the Master Trust. The investments in the pension and OPEB plans are measured at fair value within a hierarchy that prioritizes the inputs to fair value measurements into three levels. See Note 19. Fair Value Measurements for more information on fair value guidance. Use of the Master Trust permits the commingling of pension plan assets and OPEB plan assets for investment and administrative purposes. Although assets of the plans are commingled in the Master Trust, the Trustee maintains supporting records for the purpose of allocating the net gain or loss of the investment account to the respective participating plans. The net investment income of the investment assets is allocated by the Trustee to each participating plan based on the relationship of the interest of each plan to the total of the interests of the participating plans. As of December 31, 2019, the pension plan interest and OPEB plan interest in such assets of the Master Trust were approximately 92% and 8%, respectively.

The following tables present information about the investments measured at fair value on a recurring basis as of December 31, 2019 and 2018, including the fair value measurements and the levels of inputs used in determining those fair values.

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	Recurring Fair Value Measurements as of December 31, 2019
				Quoted Market Prices for Identical Assets			Significant Other Observable Inputs		Significant Unobservable Inputs
Description	Total			(Level 1)			(Level 2)		(Level 3)
	Millions
Cash Equivalents (A)	$	104		$	103		$	1	$	—
Equity Securities
Common Stock (B)	1,487			1,487			—		—
Commingled (C)	1,707			1,042			665		—
Preferred Stock (B)	19			19			—		—
Other (D)	3			3			—		—
Debt Securities (E)
U.S. Treasury	544			—			544		—
Government—Other	284			—			284		—
Corporate	837			—			837		—
Commingled	3			3			—		—
Other (Future Contracts)	(3		)	(3		)	—		—
Subtotal Fair Value	$	4,985		$	2,654		$	2,331	$	—
Measured at net asset value practical expedient
Commingled—Equities (F)	1,154
Real Estate Investment (G)	302
Private Equity (H)	8
Total Fair Value (I)	$	6,449




	Recurring Fair Value Measurements as of December 31, 2018
			Quoted Market Prices for Identical Assets		Significant Other Observable Inputs		Significant Unobservable Inputs
Description	Total		(Level 1)		(Level 2)		(Level 3)
	Millions
Cash Equivalents (A)	$	99	$	88	$	11	$	—
Equity Securities
Common Stock (B)	1,156		1,156		—		—
Commingled (C)	1,338		960		378		—
Preferred Stock (B)	7		7		—		—
Other (D)	1		1		—		—
Debt Securities (E)
U.S. Treasury	526		—		526		—
Government—Other	302		—		302		—
Corporate	948		—		948		—
Subtotal Fair Value	$	4,377	$	2,212	$	2,165	$	—
Measured at net asset value practical expedient
Commingled—Equities (F)	1,208
Private Equity (H)	10
Total Fair Value (I)	$	5,595


(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.

The following table provides the percentage of fair value of total plan assets for each major category of plan assets held for the qualified pension and OPEB plans as of the measurement date, December 31:




	As of December 31,
Investments	2019		2018
Equity Securities	68	%	66	%
Debt Securities	26		32
Other Investments	6		2
Total Percentage	100	%	100	%

PSEG utilizes forecasted returns, risk, and correlation of all asset classes in order to develop an efficient portfolio. PSEG’s latest asset/liability study indicates that a long-term target asset allocation of 59% equities, 18% real asset and 23% fixed income is consistent with the funds’ financial objectives. Derivative financial instruments are used by the plans’ investment managers primarily to adjust the fixed income duration of the portfolio and hedge the currency risk component of foreign investments. The expected long-term rate of return on plan assets was 7.8% for 2019 and will be 7.7% for 2020. This expected return was determined based on the study discussed above, including a premium for active management and considered the plans’ historical annualized rate of return since inception.

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Plan Contributions

PSEG does not plan to contribute to its pension and OPEB plans in 2020.

Estimated Future Benefit Payments

The following pension benefit and postretirement benefit payments are expected to be paid to plan participants.




Year	Pension Benefits		Other Benefits
	Millions
2020	$	382	$	90
2021	354		85
2022	367		86
2023	378		86
2024	389		86
2025-2029	2,074		409
Total	$	3,944	$	842

401(k) Plans

PSEG sponsors two 401(k) plans, which are defined contribution retirement plans subject to the Employee Retirement Income Security Act (ERISA). Eligible represented employees of PSEG’s subsidiaries participate in the PSEG Employee Savings Plan (Savings Plan), while eligible non-represented employees of PSEG’s subsidiaries participate in the PSEG Thrift and Tax-Deferred Savings Plan (Thrift Plan). Eligible employees may contribute up to 50% of their compensation to these plans, not to exceed the Internal Revenue Service (IRS) maximums, including any catch-up contributions for those employees age 50 and above. PSEG matches 50% of such employee contributions up to 7% of pay for Savings Plan participants and up to 8% of pay for Thrift Plan participants. The amounts paid for employer matching contributions to the plans for PSEG, PSE&G and PSEG Power are detailed as follows:




	Thrift Plan and Savings Plan
	Years Ended December 31,
	2019		2018		2017
	Millions
PSE&G	$	25	$	26	$	25
PSEG Power	10		10		11
Other	5		5		5
Total Employer Matching Contributions	$	40	$	41	$	41

Servco Pension and OPEB

Servco sponsors a qualified pension plan and OPEB plan covering its employees who meet certain eligibility criteria. Under the OSA, employee benefit costs for these plans are funded by LIPA. See Note 5. Variable Interest Entity. These obligations, as well as the offsetting long-term receivable, are separately presented on the Consolidated Balance Sheet of PSEG.

The following table provides a roll-forward of the changes in Servco’s benefit obligation and the fair value of its plan assets during the years ended December 31, 2019 and 2018. It also provides the funded status of the plans and the amounts recognized and amounts not recognized on the Consolidated Balance Sheets at the end of both years.

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	Pension Benefits						Other Benefits
	2019			2018			2019			2018
	Millions
Change in Benefit Obligation
Benefit Obligation at Beginning of Year	$	321		$	320		$	501		$	542
Service Cost	26			30			16			18
Interest Cost	14			12			22			20
Actuarial (Gain) Loss	96			(38		)	96			(73		)
Gross Benefits Paid	(4		)	(3		)	(6		)	(6		)
Plan Amendments	—			—			(3		)	—
Benefit Obligation at End of Year (A)	$	453		$	321		$	626		$	501
Change in Plan Assets
Fair Value of Assets at Beginning of Year	$	212		$	191		$	—		$	—
Actual Return on Plan Assets	46			(16		)	—			—
Employer Contributions	28			40			6			6
Gross Benefits Paid	(4		)	(3		)	(6		)	(6		)
Fair Value of Assets at End of Year	$	282		$	212		$	—		$	—
Funded Status
Funded Status (Plan Assets less Benefit Obligation)	$	(171	)	$	(109	)	$	(626	)	$	(501	)
Additional Amounts Recognized in the Consolidated Balance Sheets
Accrued Pension Costs of Servco	$	(171	)	$	(109	)	N/A			N/A
OPEB Costs of Servco	N/A			N/A			(626		)	(501		)
Amounts Recognized (B)	$	(171	)	$	(109	)	$	(626	)	$	(501	)


(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.

Pension and OPEB costs of Servco are accounted for according to the OSA. Servco recognizes expenses for contributions to its pension plan trusts and for OPEB payments made to retirees. Operating Revenues are recognized for the reimbursement of these costs. The pension-related revenues and costs for 2019, 2018 and 2017 were $28 million, $40 million and $35 million, respectively. Servco has contributed its entire planned contribution amount to its pension plan trusts during 2019. The OPEB-related revenues earned and costs incurred were $6 million, $6 million and $4 million in 2019, 2018 and 2017, respectively. The following assumptions were used to determine the benefit obligations of Servco:




	Pension Benefits						Other Benefits
	2019		2018		2017		2019			2018			2017
Weighted-Average Assumptions Used to Determine Benefit Obligations as of December 31
Discount Rate	3.52	%	4.60	%	3.90	%	3.60		%	4.67		%	3.96		%
Rate of Compensation Increase	3.25	%	3.25	%	3.25	%	3.25		%	3.25		%	3.25		%
Assumed Health Care Cost Trend Rates as of December 31
Health Care Costs
Immediate Rate							6.94		%	8.03		%	7.69		%
Ultimate Rate							4.75		%	4.75		%	4.75		%
Year Ultimate Rate Reached							2029			2026			2026
							Millions
Effect of a 1% Increase in the Assumed Rate of Increase in Health Care Benefit Costs
Postretirement Benefit Obligation							$	135		$	108		$	131
Effect of a 1% Decrease in the Assumed Rate of Increase in Health Care Benefit Costs
Postretirement Benefit Obligation							$	(104	)	$	(83	)	$	(99	)

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Plan Assets

All the investments of Servco’s pension plans are held in a trust account by the Trustee and consist of an undivided interest in an investment account of the Master Trust. The investments in the pension are measured at fair value within a hierarchy that prioritizes the inputs to fair value measurements into three levels. See Note 19. Fair Value Measurements for more information on fair value guidance. The Actuary maintains supporting records for the purpose of allocating the net gain or loss of the investment account to the respective participating plans. The net investment income of the investment assets is allocated by the Actuary to each participating plan based on the relationship of the interest of each plan to the total of the interests of the participating plans.

The following tables present information about Servco’s investments measured at fair value on a recurring basis as of December 31, 2019 and 2018, including the fair value measurements and the levels of inputs used in determining those fair values.




	Recurring Fair Value Measurements as of December 31, 2019
			Quoted Market Prices for Identical Assets		Significant Other Observable Inputs		Significant Unobservable Inputs
Description	Total		(Level 1)		(Level 2)		(Level 3)
	Millions
Commingled Equities (A)	$	202	$	—	$	202	$	—
Commingled Bonds (A)	80		—		80		—
Total	$	282	$	—	$	282	$	—




	Recurring Fair Value Measurements as of December 31, 2018
			Quoted Market Prices for Identical Assets		Significant Other Observable Inputs		Significant Unobservable Inputs
Description	Total		(Level 1)		(Level 2)		(Level 3)
	Millions
Commingled Equities (A)	$	141	$	—	$	141	$	—
Commingled Bonds (A)	71		—		71		—
Total	$	212	$	—	$	212	$	—


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

The following table provides the percentage of fair value of total plan assets for each major category of plan assets held for the qualified pension and OPEB plans of Servco as of the measurement date, December 31:




	As of December 31,
Investments	2019		2018
Equity Securities	72	%	67	%
Debt Securities	28		33
Total Percentage	100	%	100	%

Servco utilizes forecasted returns, risk, and correlation of all asset classes in order to develop an efficient portfolio. The results from Servco’s latest asset/liability study indicated that a long-term target asset allocation of 60% equities, 15% real assets and 25% fixed income is consistent with the funds’ financial objectives. The expected long-term rate of return on plan assets was 7.6% for 2019 and will be 7.6% for 2020. This expected return was determined based on the study discussed above, including a premium for active management.

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Plan Contributions

Servco plans to contribute $30 million into its pension plan during 2020.

Estimated Future Benefit Payments

The following pension benefit and postretirement benefit payments are expected to be paid to Servco’s plan participants:




Year	Pension Benefits		Other Benefits
	Millions
2020	$	6	$	7
2021	8		9
2022	10		11
2023	12		13
2024	14		15
2025-2029	109		104
Total	$	159	$	159

Servco 401(k) Plans

Servco sponsors two 401(k) plans, which are defined contribution retirement plans subject to ERISA. Eligible non-represented employees of Servco participate in the Long Island Electric Utility Servco LLC Incentive Thrift Plan I (Thrift Plan I), and eligible represented employees of Servco participate in the Long Island Electric Utility Servco LLC Incentive Thrift Plan II (Thrift Plan II). Participants in the plans may contribute up to 50% of their eligible compensation to these plans, not to exceed the IRS maximums, including any catch-up contributions for those employees age 50 and above. Servco does not provide an employer match or core contribution for employees in Thrift Plan II. For employees in Thrift Plan I, Servco matches 50% of such employee contributions up to 8% of eligible compensation and provides core contributions (based on years of service and age) to employees who do not participate in Servco’s Retirement Income Plan. The amounts expensed by Servco for employer matching contributions for the years ended December 31, 2019, 2018 and 2017 were $8 million, $7 million and $6 million, respectively, and pursuant to the OSA, Servco recognizes Operating Revenues for the reimbursement of these costs.

Note 15. Commitments and Contingent Liabilities

Guaranteed Obligations

PSEG Power’s activities primarily involve the purchase and sale of energy and related products under transportation, physical, financial and forward contracts at fixed and variable prices. These transactions are with numerous counterparties and brokers that may require cash, cash-related instruments or guarantees as a form of collateral.

PSEG Power has unconditionally guaranteed payments to counterparties on behalf of its subsidiaries in commodity-related transactions in order to


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


•	obtain credit.

PSEG Power is subject to


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


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

Under these agreements, guarantees cover lines of credit between entities and are often reciprocal in nature. The exposure between counterparties can move in either direction.

In order for PSEG Power to incur a liability for the face value of the outstanding guarantees,


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


•	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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PSEG Power believes the probability of this result is unlikely. For this reason, PSEG Power believes that the current exposure at any point in time is a more meaningful representation of the potential liability under these guarantees. Current exposure consists of the net of accounts receivable and accounts payable and the forward value on open positions, less any collateral posted.

Changes in commodity prices can have a material impact on collateral requirements under such contracts, which are posted and received primarily in the form of cash and letters of credit. PSEG Power also routinely enters into futures and options transactions for electricity and natural gas as part of its operations. These futures contracts usually require a cash margin deposit with brokers, which can change based on market movement and in accordance with exchange rules.

In addition to the guarantees discussed above, PSEG Power has also provided payment guarantees to third parties and regulatory authorities on behalf of its affiliated companies. These guarantees support various other non-commodity related obligations.

The following table shows the face value of PSEG Power’s outstanding guarantees, current exposure and margin positions as of December 31, 2019 and 2018.




	As of December 31, 2019			As of December 31, 2018
	Millions
Face Value of Outstanding Guarantees	$	1,854		$	1,772
Exposure under Current Guarantees	$	171		$	198

Letters of Credit Margin Posted	$	121		$	115
Letters of Credit Margin Received	$	29		$	26

Cash Deposited and Received
Counterparty Cash Collateral Deposited	$	—		$	—
Counterparty Cash Collateral Received	$	(4	)	$	(10	)
Net Broker Balance Deposited (Received)	$	48		$	403

Additional Amounts Posted
Other Letters of Credit	$	82		$	52

As part of determining credit exposure, PSEG Power nets receivables and payables with the corresponding net fair values of energy contracts. See Note 18. Financial Risk Management Activities for further discussion. In accordance with PSEG’s accounting policy, where it is applicable, cash (received)/deposited is allocated against derivative asset and liability positions with the same counterparty on the face of the Consolidated Balance Sheet. The remaining balances of net cash (received)/deposited after allocation are generally included in Accounts Payable and Receivable, respectively.

In addition to amounts for outstanding guarantees, current exposure and margin positions, PSEG and PSEG Power have posted letters of credit to support PSEG Power’s various other non-energy contractual and environmental obligations. See the preceding table.

Environmental Matters

Passaic River

Lower Passaic River Study Area

The U.S. Environmental Protection Agency (EPA) has determined that a 17-mile stretch of the Passaic River (Lower Passaic River Study Area (LPRSA)) in New Jersey is a “Superfund” site under the Federal Comprehensive Environmental Response, Compensation and Liability Act of 1980 (CERCLA). PSE&G and certain of its predecessors conducted operations at properties in this area, including at one site that was transferred to PSEG Power.

Certain Potentially Responsible Parties (PRPs), including PSE&G and PSEG Power, formed a Cooperating Parties Group (CPG) and agreed to conduct a Remedial Investigation and Feasibility Study of the LPRSA. The CPG allocated, on an interim basis, the associated costs among its members. The interim allocation is subject to change. In June 2019, the EPA conditionally approved the CPG’s Remedial Investigation. In August 2019, the CPG submitted a draft Feasibility Study (FS) to the EPA which evaluated various adaptive management scenarios for the remediation of only the upper 9 miles of the LPRSA. The CPG is evaluating the EPA’s comments received to date on the draft FS.

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Separately, the EPA has released a Record of Decision (ROD) for the LPRSA’s lower 8.3 miles that requires the removal of sediments at an estimated cost of $2.3 billion (ROD Remedy). An EPA-commenced process to allocate the associated costs is underway and PSEG cannot predict the outcome. Occidental Chemical Corporation (OCC), one of the PRPs, has commenced the design of the ROD Remedy, but declined to participate in the allocation process. Instead, it filed suit against PSE&G and others seeking cost recovery and contribution under CERCLA but has not quantified alleged damages. The litigation is ongoing and PSEG cannot predict the outcome.

Two PRPs, Tierra Solutions, Inc. (Tierra) and Maxus Energy Corporation (Maxus), have filed for Chapter 11 bankruptcy. The trust representing the creditors in this proceeding has filed a complaint asserting claims against Tierra’s and Maxus’ current and former parent entities, among others. Any damages awarded may be used to fund the remediation of the LPRSA.

As of December 31, 2019, PSEG has accrued approximately $65 million for this matter. Of this amount, PSE&G has accrued $52 million as an Environmental Costs Liability and a corresponding Regulatory Asset based on its continued ability to recover such costs in its rates. PSEG Power has accrued $13 million as an Other Noncurrent Liability with the corresponding O&M Expense.

The outcome of this matter is uncertain, and until (i) a final remedy for the entire LPRSA is selected and an agreement is reached by the PRPs to fund it, (ii) PSE&G’s and PSEG Power’s respective shares of the costs are determined, and (iii) PSE&G’s ability to recover the costs in its rates is determined, it is not possible to predict this matter’s ultimate impact on PSEG’s financial statements. It is possible that PSE&G and PSEG Power will record additional costs beyond what they have accrued, and that such costs could be material, but PSEG cannot at the current time estimate the amount or range of any additional costs.

Natural Resource Damage Claims

New Jersey and certain federal regulators have alleged that PSE&G, PSEG Power and 56 other PRPs may be liable for natural resource damages within the LPRSA. In particular, PSE&G, PSEG Power and other PRPs received notice from federal regulators of the regulators’ intent to move forward with a series of studies assessing potential damages to natural resources at the Diamond Alkali Superfund Site, which includes the LPRSA and the Newark Bay Study Area. PSE&G and PSEG Power are unable to estimate their respective portions of any possible loss or range of loss related to this matter.

Newark Bay Study Area

The EPA has established the Newark Bay Study Area, which is an extension of the LPRSA and includes Newark Bay and portions of surrounding waterways. The EPA has notified PSEG and 11 other PRPs of their potential liability. PSE&G and PSEG Power are unable to estimate their respective portions of any loss or possible range of loss related to this matter. In December 2018, PSEG Power completed the sale of the site of the Hudson electric generating station. PSEG Power contractually transferred all land rights and structures on the Hudson site to a third-party purchaser, along with the assumption of the environmental liabilities for the site.

MGP Remediation Program

PSE&G is working with the New Jersey Department of Environmental Protection (NJDEP) to assess, investigate and remediate environmental conditions at its former MGP sites. To date, 38 sites requiring some level of remedial action have been identified. Based on its current studies, PSE&G has determined that the estimated cost to remediate all MGP sites to completion could range between $357 million and $400 million on an undiscounted basis through 2023, including its $52 million share for the Passaic River as discussed above. Since no amount within the range is considered to be most likely, PSE&G has recorded a liability of $357 million as of December 31, 2019. Of this amount, $68 million was recorded in Other Current Liabilities and $289 million was reflected as Environmental Costs in Noncurrent Liabilities. PSE&G has recorded a $357 million Regulatory Asset with respect to these costs. PSE&G periodically updates its studies taking into account any new regulations or new information which could impact future remediation costs and adjusts its recorded liability accordingly. PSE&G has agreed to conduct sampling in the Passaic River to delineate coal tar from certain MGP sites that abut the Passaic River Superfund site. PSEG cannot determine at this time whether this will have an impact on the Passaic River Superfund remedy.

Clean Water Act (CWA) Section 316(b) Rule

The EPA’s CWA Section 316(b) rule establishes requirements for the regulation of cooling water intakes at existing power plants and industrial facilities with a design flow of more than two million gallons of water per day. The EPA requires that National Pollutant Discharge Elimination System permits be renewed every five years and that each state Permitting Director manage renewal permits for its respective power generation facilities on a case by case basis. The NJDEP manages the permits under the New Jersey Pollutant Discharge Elimination System (NJPDES) program. Connecticut and New York also have permits to manage their respective pollutant discharge elimination system programs.

In June 2016, the NJDEP issued a final NJPDES permit for Salem. In July 2016, the Delaware Riverkeeper Network (Riverkeeper) filed an administrative hearing request challenging certain conditions of the permit, including the NJDEP’s

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application of the 316(b) rule. If the Riverkeeper’s challenge is successful, PSEG Power may be required to incur additional costs to comply with the CWA. Potential cooling water and/or service water system modification costs could be material and could adversely impact the economic competitiveness of this facility. The NJDEP had granted the hearing request but no hearing date has been established.

State permitting decisions at BH3 and New Haven could also have a material impact on PSEG Power’s ability to renew permits at its existing larger once-through cooled plants without making significant upgrades to existing intakes and cooling systems. PSEG Power has proposed to continue to operate BH3 without making the capital expenditures for modification to the existing intake structure and retire BH3 in 2021, which is four years earlier than the previously estimated useful life ending in 2025. PSEG Power is unable to predict the outcome of these permitting decisions and the effect, if any, that they may have on PSEG Power’s future capital requirements, financial condition or results of operations.

Jersey City, New Jersey Subsurface Feeder Cable Matter

In October 2016, a discharge of dielectric fluid from subsurface feeder cables located in the Hudson River near Jersey City, New Jersey, was identified and reported to the NJDEP. The feeder cables are located within a subsurface easement granted to PSE&G by the property owners, Newport Associates Development Company (NADC) and Newport Associates Phase I Developer Limited Partnership. The feeder cables are subject to agreements between PSE&G and Consolidated Edison Company of New York, Inc. (Con Edison) and are jointly owned by PSE&G and Con Edison, with PSE&G owning the portion of the cables located in New Jersey and Con Edison owning the portion of the cables located in New York. The NJDEP declared an emergency and an emergency response action was undertaken to investigate, contain, remediate and stop the fluid discharge; to assess, repair and restore the cables to good working order, if feasible; and to restore the property. The U.S. Coast Guard transitioned control of the federal response to the EPA, and the EPA ended the federal response to the matter in 2018. The response is a part of the NJDEP site remediation program. The parties may be subject to the assessment of civil penalties related to the discharge and response. We are currently in discussions with the U.S. Coast Guard regarding the reimbursement of costs associated with the federal response to this matter and potential payment of civil penalties. We cannot predict the outcome of these discussions.

The impacted cable was repaired in late September 2017; however, small amounts of residual dielectric fluid believed to be contained within the marina sediment continue to appear on the surface and response actions related to the fluid discharge are ongoing, although at a significantly reduced scale. PSE&G remains concerned about future leaks and potential environmental impacts as a result of reintroduction of fluid back into these lines and has determined that retirement of the affected facilities is appropriate. A lawsuit in federal court is pending to determine ultimate responsibility for the costs to address the leak among PSE&G, Con Edison and NADC. In addition, Con Edison filed counter claims against PSE&G and NADC, including seeking injunctive relief and damages. Based on the information currently available and depending on the outcome of the federal court action, PSE&G’s portion of the costs to address the leak may be material; however, PSE&G anticipates that it will recover these costs through regulatory proceedings.

BGS, BGSS and ZECs

PSE&G obtains its electric supply requirements through the annual New Jersey BGS auctions for two categories of customers who choose not to purchase electric supply from third-party suppliers. The first category, which represents about 79% of PSE&G’s load requirement, is residential and smaller commercial and industrial customers (BGS-Residential Small Commercial Pricing (RSCP)). The second category is larger customers that exceed a BPU-established load (kW) threshold (BGS-Commercial and Industrial Energy Pricing (CIEP)). Pursuant to applicable BPU rules, PSE&G enters into the Supplier Master Agreement with the winners of these BGS auctions following the BPU’s approval of the auction results. PSE&G has entered into contracts with winning BGS suppliers, including PSEG Power, to purchase BGS for PSE&G’s load requirements. The winners of the auction (including PSEG Power) are responsible for fulfilling all the requirements of a PJM Load-Serving Entity including the provision of capacity, energy, ancillary services, transmission and any other services required by PJM. BGS suppliers assume all volume risk and customer migration risk and must satisfy New Jersey’s renewable portfolio standards.

The BGS-CIEP auction is for a one-year supply period from June 1 to May 31 with the BGS-CIEP auction price measured in dollars per MW-day for capacity. The final price for the BGS-CIEP auction year commencing June 1, 2020 is $359.98 per MW-day, replacing the BGS-CIEP auction year price ending May 31, 2020 of $281.78 per MW-day. Energy for BGS-CIEP is priced at hourly PJM locational marginal prices for the contract period.

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PSE&G contracts for its anticipated BGS-RSCP load on a three-year rolling basis, whereby each year one-third of the load is procured for a three-year period. The contract prices in dollars per MWh for the BGS-RSCP supply, as well as the approximate load, are as follows:




	Auction Year
	2017	2018	2019	2020
36-Month Terms Ending	May 2020	May 2021	May 2022	May 2023	(A)
Load (MW)	2,800	2,900	2,800	2,800
$ per MWh	$90.78	$91.77	$98.04	$102.16


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

PSEG Power seeks to mitigate volatility in its results by contracting in advance for the sale of most of its anticipated electric output as well as its anticipated fuel needs. As part of its objective, PSEG Power has entered into contracts to directly supply PSE&G and other New Jersey EDCs with a portion of their respective BGS requirements through the New Jersey BGS auction process, described above.

PSE&G has a full-requirements contract with PSEG Power to meet the gas supply requirements of PSE&G’s gas customers. PSEG Power has entered into hedges for a portion of these anticipated BGSS obligations, as permitted by the BPU. The BPU permits PSE&G to recover the cost of gas hedging up to 115 billion cubic feet or 80% of its residential gas supply annual requirements through the BGSS tariff. Current plans call for PSEG Power to hedge on behalf of PSE&G approximately 70 billion cubic feet or 50% of its residential gas supply annual requirements. For additional information, see Note 26. Related-Party Transactions.

Pursuant to a process established by the BPU, New Jersey EDCs, including PSE&G, are required to purchase ZECs from eligible nuclear plants selected by the BPU. In April 2019, PSEG Power’s Salem 1, Salem 2 and Hope Creek nuclear plants were selected to receive ZEC revenue for approximately three years, through May 2022. PSE&G has implemented a tariff to collect a non-bypassable distribution charge in the amount of $0.004 per KWh from its retail distribution customers to be used to purchase the ZECs from these plants. PSE&G will purchase the ZECs on a monthly basis with payment to be made annually following completion of each energy year. The legislation also requires nuclear plants to reapply for any subsequent three-year periods and allows the BPU to adjust prospective ZEC payments.

Minimum Fuel Purchase Requirements

PSEG Power’s nuclear fuel strategy is to maintain certain levels of uranium and to make periodic purchases to support such levels. As such, the commitments referred to in the following table may include estimated quantities to be purchased that deviate from contractual nominal quantities. PSEG Power’s nuclear fuel commitments cover approximately 100% of its estimated uranium, enrichment and fabrication requirements through 2021 and a significant portion through 2022 at Salem, Hope Creek and Peach Bottom.

PSEG Power has various multi-year contracts for natural gas and firm transportation and storage capacity for natural gas that are primarily used to meet its obligations to PSE&G. When there is excess delivery capacity available beyond the needs of PSE&G’s customers, PSEG Power can use the gas to supply its fossil generating stations in New Jersey.

In connection with the sale of its ownership interests in the Keystone and Conemaugh generation plants in September 2019, PSEG Power transferred the related coal purchase commitments to the buyers.

As of December 31, 2019, the total minimum purchase requirements included in these commitments were as follows:




Fuel Type	PSEG Power's Share of Commitments through 2024
	Millions
Nuclear Fuel
Uranium	$	187
Enrichment	$	357
Fabrication	$	185
Natural Gas	$	1,342

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Pending FERC Matters

In June 2015, Hudson Power Transmission Developers, LLC (Hudson Power), formerly known as TranSource LLC, a merchant transmission developer, filed a complaint against PJM claiming that PJM wrongfully refused to provide data and a transparent process for evaluating transmission network upgrade requests that the transmission developer had submitted to PJM. Although not named as a respondent, the complaint identifies PSE&G as one of the companies claimed to have been involved. In January 2018, a FERC administrative law judge (ALJ) issued an order generally finding that PJM and transmission owners, including PSE&G, did not engage in wrongful conduct. In addition, the developer’s assertion of an entitlement to monetary damages was expressly denied. However, in a determination disputed by PSE&G, the order found that the PJM process lacked transparency. In August 2019, FERC reversed the ALJ’s decision on the transparency-related findings. FERC did find that PJM violated its Tariff and FERC orders, but found those errors were immaterial and ordered no remedies. Hudson Power filed comments alleging FERC erred in overturning the ALJ’s decision, which was subsequently rejected by FERC. In October 2019, FERC dismissed Hudson Power’s comments on the grounds that it did not meet FERC’s requirements for a properly filed rehearing request. Hudson Power did not seek judicial review of this decision.

PSE&G has also received requests for information and a Notice of Investigation from FERC’s Office of Enforcement concerning a transmission project. PSE&G retained outside counsel to assist with an internal investigation. PSE&G is fully cooperating with FERC’s requests for information and the investigation. It is not possible at this time to predict the outcome of this matter.

Litigation

Sewaren 7 Construction

In June 2018, a complaint was filed in federal court in Newark, New Jersey against PSEG Fossil LLC, a wholly owned subsidiary of PSEG Power, regarding an ongoing dispute with Durr Mechanical Construction, Inc. (Durr), a contractor on the Sewaren 7 project. Among other things, Durr seeks damages of $93 million and alleges that PSEG Power withheld money owed to Durr and that PSEG Power’s intentional conduct led to the inability of Durr to obtain prospective contracts. PSEG Power intends to vigorously defend against these allegations. In December 2018, Durr filed for Chapter 11 bankruptcy in the federal court in the Southern District of New York (SDNY). The SDNY bankruptcy court has allowed the New Jersey litigation to proceed. PSEG Power has accrued an amount related to outstanding invoices which does not reflect an assessment of claims and potential counterclaims in this matter. Due to its preliminary nature, PSEG Power cannot predict the outcome of this matter.

Caithness Energy, L.L.C. (Caithness)

In August 2018, Caithness, a Long Island power plant developer, filed a complaint in federal district court in the Eastern District of New York (EDNY) against PSEG and PSEG LI alleging violations of state and federal antitrust laws and a claim of intentional interference of prospective business relations. Caithness alleges that PSEG and PSEG LI interfered with LIPA’s consideration of the Caithness proposal for a 750 MW combined cycle generation project that was identified as a finalist for a Request For Proposal issued by LIPA. The complaint alleges hundreds of millions of dollars of harm. The EDNY granted PSEG’s and PSEG LI’s motion to dismiss the complaint but gave Caithness an opportunity to file an amended claim. Pursuant to a request by Caithness, the EDNY dismissed the antitrust claims with prejudice but allowed Caithness the opportunity to file its claim of intentional interference of prospective business in state court. Caithness has not yet refiled this claim in state court. PSEG intends to vigorously defend against these allegations. Based upon the preliminary nature of this matter, a loss is not considered probable nor is the amount of loss, if any, estimable as of December 31, 2019.

Hudson Power

In January 2019, Hudson Power filed a complaint against PJM, PSE&G and three other transmission owners in Pennsylvania state court. Hudson Power sued the transmission owner defendants for fraud and intentional misrepresentation relating to information provided to PJM and FERC regarding the costs of upgrades for Hudson Power’s proposed project. These allegations appear to be based on alleged conduct that is the subject of the Hudson Power proceeding discussed under “Pending FERC Matters.” This action was removed to federal court in the Eastern District of Pennsylvania in February 2019. In light of the FERC proceeding, the federal court granted a motion to stay the federal proceeding until the conclusion of the FERC proceeding. In December 2019, the parties filed a stipulation with the federal court that dismissed all claims brought by Hudson Power, concluding the litigation.

Telephone Consumer Protection Act (TCPA) Matter

In February 2020, a putative class action complaint was filed in federal court in Newark, New Jersey against PSEG for violations of the TCPA related to alleged automated telemarketing calls directed to plaintiffs’ cellular telephone numbers. Due to its preliminary nature, PSEG cannot predict the outcome of this matter.

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Other Litigation and Legal Proceedings

PSEG and its subsidiaries are party to various lawsuits in the ordinary course of business. In view of the inherent difficulty in predicting the outcome of such matters, PSEG, PSE&G and PSEG Power generally cannot predict the eventual outcome of the pending matters, the timing of the ultimate resolution of these matters, or the eventual loss, fines or penalties related to each pending matter.

In accordance with applicable accounting guidance, a liability is accrued when those matters present loss contingencies that are both probable and reasonably estimable. In such cases, there may be an exposure to loss in excess of any amounts accrued. PSEG will continue to monitor the matter for further developments that could affect the amount of the accrued liability that has been previously established.

Based on current knowledge, management does not believe that loss contingencies arising from pending matters, other than the matters described herein, could have a material adverse effect on PSEG’s, PSE&G’s or PSEG Power’s consolidated financial position or liquidity. However, in light of the inherent uncertainties involved in these matters, some of which are beyond PSEG’s control, and the large or indeterminate damages sought in some of these matters, an adverse outcome in one or more of these matters could be material to PSEG’s, PSE&G’s or PSEG Power’s results of operations or liquidity for any particular reporting period.

Nuclear Insurance Coverages and Assessments

PSEG Power is a member of the joint underwriting association, American Nuclear Insurers (ANI), which provides nuclear liability insurance coverage at the Salem and Hope Creek site and the Peach Bottom site. The ANI policies are designed to satisfy the financial protection requirements outlined in the Price-Anderson Act, which sets the limit of liability for claims that could arise from an incident involving any licensed nuclear facility in the United States. The limit of liability per incident per site is composed of primary and excess layers. As of December 31, 2019, nuclear sites were required to purchase $450 million of primary liability coverage for each site (through ANI). The primary layer is supplemented by an excess layer, which is an industry self-insurance pool. In the event a nuclear site, which is part of the industry self-insurance pool, has a claim that exceeds the primary layer, each licensee would be assessed a prorated share of the excess layer. The excess layer limit is $13.5 billion. PSEG Power’s maximum aggregate assessment per incident is $433 million (based on PSEG Power’s ownership interests in Salem, Hope Creek and Peach Bottom) and its maximum aggregate annual assessment per incident is $65 million. If the damages exceed the limit of liability, Congress could impose further revenue-raising measures on the nuclear industry to pay claims. Further, a decision by the U.S. Supreme Court, not involving PSEG Power, held that the Price-Anderson Act did not preclude punitive damage awards based on state law claims.

PSEG Power is also a member of an industry mutual insurance company, Nuclear Electric Insurance Limited (NEIL), which provides the property, decontamination and decommissioning liability insurance at the Salem and Hope Creek site and the Peach Bottom site. NEIL also provides replacement power coverage through its accidental outage policy. NEIL policies may make retrospective premium assessments in the case of adverse loss experience. The current maximum aggregate annual retrospective premium obligation for PSEG Power is approximately $61 million. NEIL requires its members to maintain an investment grade credit rating or to ensure collectability of their annual retrospective premium obligation by providing a financial guarantee, letter of credit, deposit premium, or some other means of assurance. Certain provisions in the NEIL policies provide that the insurer may suspend coverage with respect to all nuclear units on a site without notice if the NRC suspends or revokes the operating license for any unit on that site, issues a shutdown order with respect to such unit or issues a confirmatory order keeping such unit down.

The ANI and NEIL policies all include coverage for claims arising out of acts of terrorism. However, NEIL policies are subject to an industry aggregate limit of $3.2 billion plus such additional amounts as NEIL recovers for such losses from reinsurance, indemnity and any other source applicable to such losses.

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Note 16. Debt and Credit Facilities

Long-Term Debt




		As of December 31,
	Maturity	2019			2018
		Millions
PSEG
Term Loan:
Variable Rate	2019	$	—		$	350
Variable Rate	2020	700			700
Total Term Loan		700			1,050
Senior Notes:
1.60%	2019	—			400
2.00%	2021	300			300
2.65%	2022	700			700
2.88%	2024	750			—
Total Senior Notes		1,750			1,400
Principal Amount Outstanding		2,450			2,450
Amounts Due Within One Year		(700		)	(750		)
Net Unamortized Discount and Debt Issuance Costs		(9		)	(7		)
Total Long-Term Debt of PSEG		$	1,741		$	1,693

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		As of December 31,
	Maturity	2019			2018
		Millions
PSE&G
First and Refunding Mortgage Bonds (A):
9.25%	2021	$	134		$	134
8.00%	2037	7			7
5.00%	2037	8			8
Total First and Refunding Mortgage Bonds		149			149
Medium-Term Notes (MTNs) (A):
1.80%	2019	—			250
2.00%	2019	—			250
3.50%	2020	250			250
7.04%	2020	9			9
1.90%	2021	300			300
2.38%	2023	500			500
3.25%	2023	325			325
3.75%	2024	250			250
3.15%	2024	250			250
3.05%	2024	250			250
3.00%	2025	350			350
2.25%	2026	425			425
3.00%	2027	425			425
3.70%	2028	375			375
3.65%	2028	325			325
3.20%	2029	375			—
5.25%	2035	250			250
5.70%	2036	250			250
5.80%	2037	350			350
5.38%	2039	250			250
5.50%	2040	300			300
3.95%	2042	450			450
3.65%	2042	350			350
3.80%	2043	400			400
4.00%	2044	250			250
4.05%	2045	250			250
4.15%	2045	250			250
3.80%	2046	550			550
3.60%	2047	350			350
4.05%	2048	325			325
3.85%	2049	375			—
3.20%	2049	400			—
Total MTNs		9,759			9,109
Principal Amount Outstanding		9,908			9,258
Amounts Due Within One Year		(259		)	(500		)
Net Unamortized Discount and Debt Issuance Costs		(81		)	(74		)
Total Long-Term Debt of PSE&G		$	9,568		$	8,684

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		As of December 31,
	Maturity	2019			2018
		Millions
PSEG Power
Senior Notes:
5.13%	2020	$	406		$	406
3.00%	2021	700			700
4.15%	2021	250			250
3.85%	2023	700			700
4.30%	2023	250			250
8.63%	2031	500			500
Total Senior Notes		2,806			2,806
Pollution Control Notes:
Floating Rate (B)	2022	44			44
Total Pollution Control Notes		44			44
Principal Amount Outstanding		2,850			2,850
Amounts Due Within One Year		(406		)	(44		)
Net Unamortized Discount and Debt Issuance Costs		(10		)	(15		)
Total Long-Term Debt of PSEG Power		$	2,434		$	2,791


(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.

Long-Term Debt Maturities

The aggregate principal amounts of maturities for each of the five years following December 31, 2019 are as follows:




Year	PSEG		PSE&G		PSEG Power		Total

2020	$	700	$	259	$	406	$	1,365
2021	300		434		950		1,684
2022	700		—		44		744
2023	—		825		950		1,775
2024	750		750		—		1,500
Thereafter	—		7,640		500		8,140
Total	$	2,450	$	9,908	$	2,850	$	15,208

Long-Term Debt Financing Transactions

During 2019, PSEG and its subsidiaries had the following Long-Term Debt issuances, maturities and redemptions:

PSEG


•	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.

PSE&G

•issued $400 million of 3.20% Secured Medium-Term Notes, Series M, due August 2049,

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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.

In January 2020, PSE&G issued $300 million of 2.45% Medium-Term Notes, Series N, due January 2030 and $300 million of 3.15% Medium-Term Notes, Series N, due January 2050.

PSEG Power


•	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.

Short-Term Liquidity

The commitments under the $4.2 billion credit facilities are provided by a diverse bank group. As of December 31, 2019, the total available credit capacity was $2.9 billion.

As of December 31, 2019, no single institution represented more than 9% of the total commitments in the credit facilities.

As of December 31, 2019, the total credit capacity was in excess of the anticipated maximum liquidity requirements over PSEG’s 12-month planning horizon.

Each of the credit facilities is restricted as to availability and use to the specific companies as listed in the following table; however, if necessary, the PSEG facilities can also be used to support our subsidiaries’ liquidity needs.

The total credit facilities and available liquidity as of December 31, 2019 were as follows:




	As of December 31, 2019
Company/Facility	Total Facility		Usage (D)		Available Liquidity		Expiration Date	Primary Purpose
	Millions
PSEG
5-year Credit Facilities (A)	$	1,500	$	796	$	704	Mar 2023	Commercial Paper Support/Funding/Letters of Credit
Total PSEG	$	1,500	$	796	$	704
PSE&G
5-year Credit Facility (B)	$	600	$	379	$	221	Mar 2023	Commercial Paper Support/Funding/Letters of Credit
Total PSE&G	$	600	$	379	$	221
PSEG Power
3-year Letter of Credit Facilities	$	200	$	121	$	79	Sept 2021	Letters of Credit
5-year Credit Facilities (C)	1,900		40		1,860		Mar 2023	Funding/Letters of Credit
Total PSEG Power	$	2,100	$	161	$	1,939
Total	$	4,200	$	1,336	$	2,864

(A)PSEG facilities will be reduced by $9 million in March 2022.


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


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


(D)	The primary use of PSEG’s and PSE&G’s credit facilities is to support their respective Commercial Paper Programs, under which as of December 31, 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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Fair Value of Debt

The estimated fair values, carrying amounts and methods used to determine fair value of long-term debt as of December 31, 2019 and 2018 are included in the following table and accompanying notes as of December 31, 2019 and 2018. See Note 19. Fair Value Measurements for more information on fair value guidance and the hierarchy that prioritizes the inputs to fair value measurements into three levels.




	December 31, 2019				December 31, 2018
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	Millions
Long-Term Debt:
PSEG (A) (B)	$	2,441	$	2,479	$	2,443	$	2,397
PSE&G (B)	9,827		11,107		9,184		9,374
PSEG Power (B)	2,840		3,137		2,835		2,996
Total Long-Term Debt	$	15,108	$	16,723	$	14,462	$	14,767


(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.

Note 17. Schedule of Consolidated Capital Stock




	As of December 31,
	Outstanding Shares		Book Value
	2019	2018	2019		2018
	Millions
PSEG Common Stock (no par value) (A)
Authorized 1,000 shares	504	504	$	4,172	$	4,172


(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.

As of December 31, 2019, PSE&G had an aggregate of 7.5 million shares of $100 par value and 10 million shares of $25 par value Cumulative Preferred Stock, which were authorized and unissued and which, upon issuance, may or may not provide for mandatory sinking fund redemption.

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Note 18. Financial Risk Management Activities

Derivative accounting guidance requires that a derivative instrument be recognized as either an asset or a liability at fair value, with changes in fair value of the derivative recognized in earnings each period. Other accounting treatments are available through special election and designation provided that the derivative instrument meets specific, restrictive criteria, both at the time of designation and on an ongoing basis. These alternative permissible treatments include NPNS, cash flow hedge and fair value hedge accounting. PSEG, PSEG Power and PSE&G have applied the NPNS scope exception to certain derivative contracts for the forward sale of generation, power procurement agreements and fuel agreements. PSEG uses interest rate swaps and other derivatives, which are designated and qualifying as cash flow or fair value hedges. PSEG Power enters into additional contracts that are derivatives, but are not designated as either cash flow hedges or fair value hedges. These transactions are economic hedges and are recorded at fair market value.

Commodity Prices

Within PSEG and its affiliate companies, PSEG Power has the most exposure to commodity price risk. PSEG Power is exposed to commodity price risk primarily relating to changes in the market price of electricity, fossil fuels and other commodities. Fluctuations in market prices result from changes in supply and demand, fuel costs, market conditions, weather, state and federal regulatory policies, environmental policies, transmission availability and other factors. PSEG Power uses a variety of derivative and non-derivative instruments, such as financial options, futures, swaps, fuel purchases and forward purchases and sales of electricity, to manage the exposure to fluctuations in commodity prices and optimize the value of PSEG Power’s expected generation. PSEG Power also uses derivatives to hedge a portion of its anticipated BGSS obligations with PSE&G. For additional information see Note 15. Commitments and Contingent Liabilities. Changes in the fair market value of these derivative contracts are recorded in earnings.

Interest Rates

PSEG, PSEG Power and PSE&G are subject to the risk of fluctuating interest rates in the normal course of business. Exposure to this risk is managed by targeting a balanced debt maturity profile which limits refinancing in any given period or interest rate environment. In addition, they have used a mix of fixed and floating rate debt and interest rate swaps.

Fair Value Hedges

PSEG enters into fair value hedges to convert fixed-rate debt into variable-rate debt. The changes in fair value of the interest rate swaps are fully offset by changes in the fair value of the underlying forecasted interest payments of the debt. There were no outstanding interest rate swaps as of December 31, 2019 or 2018.

Cash Flow Hedges

PSEG uses interest rate swaps and other derivatives, which are designated and qualifying as cash flow hedges, to manage its exposure to the variability of cash flows, primarily related to variable-rate debt instruments. As of December 31, 2019, PSEG had interest rate hedges outstanding totaling $700 million. These hedges convert PSEG’s $700 million variable-rate term loan due November 2020 into a fixed-rate loan. PSEG interest rate hedges totaling $600 million were terminated during the second quarter and a loss of $(12) million was recorded in Accumulated Other Comprehensive Income (Loss) (after tax) and will amortize to interest expense over the remaining life of PSEG’s $750 million of 2.875% Senior Notes due June 2024. For additional information see Note 16. Debt and Credit Facilities.

The fair value of these hedges was $(5) million as of December 31, 2019 and there were no outstanding interest rate hedges as of December 31, 2018. The Accumulated Other Comprehensive Income (Loss) (after tax) related to outstanding and terminated interest rate derivatives designated as cash flow hedges was $(15) million and $(1) million as of December 31, 2019 and December 31, 2018, respectively. The after-tax unrealized losses on these hedges expected to be reclassified to earnings during the next 12 months are $(2) million.

Fair Values of Derivative Instruments

The following are the fair values of derivative instruments on the Consolidated Balance Sheets. The following tables also include disclosures for offsetting derivative assets and liabilities which are subject to a master netting or similar agreement. In general, the terms of the agreements provide that in the event of an early termination the counterparties have the right to offset amounts owed or owing under that and any other agreement with the same counterparty. Accordingly, and in accordance with PSEG’s accounting policy, these positions are offset on the Consolidated Balance Sheets of PSEG Power and PSEG. For additional information see Note 19. Fair Value Measurements.

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The following tabular disclosure does not include the offsetting of trade receivables and payables.




	As of December 31, 2019
	PSEG Power (A)									PSEG (A)			Consolidated
	Not Designated									Cash Flow Hedges
Balance Sheet Location	Energy- Related Contracts			Netting (B)			Total PSEG Power			Interest Rate Swaps			Total Derivatives
	Millions
Derivative Contracts
Current Assets	$	636		$	(523	)	$	113		$	—		$	113
Noncurrent Assets	163			(139		)	24			—			24
Total Mark-to-Market Derivative Assets	$	799		$	(662	)	$	137		$	—		$	137
Derivative Contracts
Current Liabilities	$	(553	)	$	522		$	(31	)	$	(5	)	$	(36	)
Noncurrent Liabilities	(139		)	138			(1		)	—			(1		)
Total Mark-to-Market Derivative (Liabilities)	$	(692	)	$	660		$	(32	)	$	(5	)	$	(37	)
Total Net Mark-to-Market Derivative Assets (Liabilities)	$	107		$	(2	)	$	105		$	(5	)	$	100




	As of December 31, 2018
		PSEG Power (A)									Consolidated
		Not Designated
Balance Sheet Location		Energy- Related Contracts			Netting (B)			Total PSEG Power			Total Derivatives
	Millions
Derivative Contracts
Current Assets		$	426		$	(415	)	$	11		$	11
Noncurrent Assets		137			(136		)	1			1
Total Mark-to-Market Derivative Assets		$	563		$	(551	)	$	12		$	12
Derivative Contracts
Current Liabilities		$	(521	)	$	510		$	(11	)	$	(11	)
Noncurrent Liabilities		(198		)	194			(4		)	(4		)
Total Mark-to-Market Derivative (Liabilities)		$	(719	)	$	704		$	(15	)	$	(15	)
Total Net Mark-to-Market Derivative Assets (Liabilities)		$	(156	)	$	153		$	(3	)	$	(3	)


(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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Certain of PSEG Power’s derivative instruments contain provisions that require PSEG Power to post collateral. This collateral may be posted in the form of cash or credit support with thresholds contingent upon PSEG Power’s credit rating from each of the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. These credit risk-related contingent features stipulate that if PSEG Power were to be downgraded to a below investment grade rating by S&P or Moody’s, it would be required to provide additional collateral. A below investment grade credit rating for PSEG Power would represent a three level downgrade from its current S&P or Moody’s ratings. This incremental collateral requirement can offset collateral requirements related to other derivative instruments that are assets with the same counterparty, where the contractual right of offset exists under applicable master agreements. PSEG Power also enters into commodity transactions on the New York Mercantile Exchange (NYMEX) and Intercontinental Exchange (ICE). The NYMEX and ICE clearing houses act as counterparties to each trade. Transactions on the NYMEX and ICE must adhere to comprehensive collateral and margin requirements.

The aggregate fair value of all derivative instruments with credit risk-related contingent features in a liability position that are not fully collateralized (excluding transactions on the NYMEX and ICE that are fully collateralized) was $35 million and $22 million as of December 31, 2019 and 2018, respectively. As of December 31, 2019 and 2018, PSEG Power had the contractual right of offset of $2 million and $7 million, respectively, related to derivative instruments that are assets with the same counterparty under master agreements and net of margin posted. If PSEG Power had been downgraded to a below investment grade rating, it would have had additional collateral obligations of $33 million and $15 million as of December 31, 2019 and 2018, respectively, related to its derivatives, net of the contractual right of offset under master agreements and the application of collateral.

The following shows the effect on the Consolidated Statements of Operations and on Accumulated Other Comprehensive Loss (AOCL) of derivative instruments designated as cash flow hedges for the years ended December 31, 2019, 2018 and 2017.




	Amount of Pre-Tax Gain (Loss) Recognized in AOCL on Derivatives								Location of Pre-Tax Gain (Loss) Reclassified from AOCL into Income	Amount of Pre-Tax Gain (Loss) Reclassified from AOCL into Income
Derivatives in Cash Flow Hedging Relationships	Years Ended December 31,									Years Ended December 31,
	2019			2018			2017			2019			2018		2017
	Millions									Millions
PSEG
Interest Rate Swaps	$	(23	)	$	(2	)	$	—	Interest Expense	$	(4	)	$	—	$	3
Total PSEG	$	(23	)	$	(2	)	$	—		$	(4	)	$	—	$	3

The effect of interest rate cash flow hedges is recorded in Interest Expense in PSEG’s Consolidated Statement of Operations. For the year ended December 31, 2019, the amount of gain or loss on interest rate hedges reclassified from Accumulated Other Comprehensive Income (Loss) into income was $(3) million after tax and immaterial as of December 31, 2018 and 2017.

The following reconciles the Accumulated Other Comprehensive Income (Loss) for derivative activity included in the AOCL of PSEG on a pre-tax and after-tax basis.




Accumulated Other Comprehensive Income (Loss)	Pre-Tax			After-Tax
	Millions
Balance as of December 31, 2017	$	—		$	—
Loss Recognized in AOCI	(2		)	(1		)
Less: Gain Reclassified into Income	—			—
Balance as of December 31, 2018	$	(2	)	$	(1	)
Loss Recognized in AOCI	(23		)	(17		)
Less: Loss Reclassified into Income	4			3
Balance as of December 31, 2019	$	(21	)	$	(15	)

The following shows the effect on the Consolidated Statements of Operations of derivative instruments not designated as hedging instruments or as NPNS for the years ended December 31, 2019, 2018 and 2017. PSEG Power’s derivative contracts reflected in this table include contracts to hedge the purchase and sale of electricity and natural gas, and the purchase of fuel. The table does not include contracts which PSEG Power has designated as NPNS, such as its BGS contracts and certain other

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energy supply contracts that it has with other utilities and companies with retail load.




Derivatives Not Designated as Hedges	Location of Pre-Tax Gain (Loss) Recognized in Income on Derivatives	Pre-Tax Gain (Loss) Recognized in Income on Derivatives
		Years Ended December 31,
		2019			2018			2017
		Millions
PSEG Power
Energy-Related Contracts	Operating Revenues	$	560		$	(182	)	$	66
Energy-Related Contracts	Energy Costs	(119		)	(9		)	(11		)
Total PSEG and PSEG Power		$	441		$	(191	)	$	55

The following table summarizes the net notional volume purchases/(sales) of open derivative transactions by commodity as of December 31, 2019 and 2018.




Type	Notional	Total		PSEG	PSEG Power		PSE&G
	Millions
As of December 31, 2019
Natural Gas	Dekatherm (Dth)	341		—	341		—
Electricity	MWh	(62	)	—	(62	)	—
Financial Transmission Rights (FTRs)	MWh	13		—	13		—
Interest Rate Swaps	U.S. Dollars	700		700	—		—
As of December 31, 2018
Natural Gas	Dth	358		—	358		—
Electricity	MWh	(74	)	—	(74	)	—
FTRs	MWh	18		—	18		—

Credit Risk

Credit risk relates to the risk of loss that PSEG Power would incur as a result of non-performance by counterparties pursuant to the terms of their contractual obligations. PSEG has established credit policies that it believes significantly minimize credit risk. These policies include an evaluation of potential counterparties’ financial condition (including credit rating), collateral requirements under certain circumstances and the use of standardized agreements, which allow for the netting of positive and negative exposures associated with a single counterparty. In the event of non-performance or non-payment by a major counterparty, there may be a material adverse impact on PSEG Power’s and PSEG’s financial condition, results of operations or net cash flows.

The following table provides information on PSEG Power’s credit risk from wholesale counterparties, net of collateral, as of December 31, 2019. It further delineates that exposure by the credit rating of the counterparties, which is determined by the lowest rating from S&P, Moody’s or an internal scoring model. In addition, it provides guidance on the concentration of credit risk to individual counterparties and an indication of the quality of PSEG Power’s credit risk by credit rating of the counterparties.

As of December 31, 2019, 99% of the net credit exposure for PSEG Power’s wholesale operations was with investment grade counterparties. Credit exposure is defined as any positive results of netting accounts receivable/accounts payable and the forward value of open positions (which includes all financial instruments including derivatives, NPNS and non-derivatives).

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Rating	Current Exposure		Securities held as Collateral		Net Exposure		Number of Counterparties >10%	Net Exposure of Counterparties >10%
	Millions							Millions
Investment Grade	$	505	$	26	$	479	2	$	263	(A)
Non-Investment Grade	3		—		3		—	—
Total	$	508	$	26	$	482	2	$	263


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

As of December 31, 2019, collateral held from counterparties where PSEG Power had credit exposure includes $4 million in cash and $22 million in letters of credit.

As of December 31, 2019, PSEG Power had 153 active counterparties.

PSE&G’s supplier master agreements are approved by the BPU and govern the terms of its electric supply procurement contracts. These agreements define a supplier’s performance assurance requirements and allow a supplier to meet its credit requirements with a certain amount of unsecured credit. The amount of unsecured credit is determined based on the supplier’s credit ratings from the major credit rating agencies and the supplier’s tangible net worth. The credit position is based on the initial market price, which is the forward price of energy on the day the procurement transaction is executed, compared to the forward price curve for energy on the valuation day. To the extent that the forward price curve for energy exceeds the initial market price, the supplier is required to post a parental guaranty or other security instrument such as a letter of credit or cash, as collateral to the extent the credit exposure is greater than the supplier’s unsecured credit limit. As of December 31, 2019, primarily all of the posted collateral was in the form of parental guarantees. The unsecured credit used by the suppliers represents PSE&G’s net credit exposure. PSE&G’s BGS suppliers’ credit exposure is calculated each business day. As of December 31, 2019, PSE&G had no net credit exposure with suppliers, including PSEG Power.

PSE&G is permitted to recover its costs of procuring energy through the BPU-approved BGS tariffs. PSE&G’s counterparty credit risk is mitigated by its ability to recover realized energy costs through customer rates.

Note 19. Fair Value Measurements

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Accounting guidance for fair value measurement emphasizes that fair value is a market-based measurement, not an entity-specific measurement, and establishes a fair value hierarchy that distinguishes between assumptions based on market data obtained from independent sources and those based on an entity’s own assumptions. The hierarchy prioritizes the inputs to fair value measurement into three levels:

Level 1—measurements utilize quoted prices (unadjusted) in active markets for identical assets or liabilities that PSEG, PSE&G and PSEG Power have the ability to access. These consist primarily of listed equity securities and money market mutual funds, as well as natural gas futures contracts executed on NYMEX.

Level 2—measurements include quoted prices for similar assets and liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, and other observable inputs such as interest rates and yield curves that are observable at commonly quoted intervals. These consist primarily of non-exchange traded derivatives such as forward contracts or options and most fixed income securities.

Level 3—measurements use unobservable inputs for assets or liabilities, based on the best information available and might include an entity’s own data and assumptions. In some valuations, the inputs used may fall into different levels of the hierarchy. In these cases, the financial instrument’s level within the fair value hierarchy is based on the lowest level of input that is significant to the fair value measurement. These consist primarily of certain electric load contracts and gas contracts.

Certain derivative transactions may transfer from Level 2 to Level 3 if inputs become unobservable and internal modeling techniques are employed to determine fair value. Conversely, measurements may transfer from Level 3 to Level 2 if the inputs become observable.

The following tables present information about PSEG’s, PSE&G’s and PSEG Power’s respective assets and (liabilities) measured at fair value on a recurring basis as of December 31, 2019 and December 31, 2018, including the fair value measurements and the levels of inputs used in determining those fair values. Amounts shown for PSEG include the amounts shown for PSE&G and PSEG Power.

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	Recurring Fair Value Measurements as of December 31, 2019
Description	Total			Netting (E)			Quoted Market Prices for Identical Assets (Level 1)			Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
	Millions
PSEG
Assets:
Cash Equivalents (A)	$	50		$	—		$	50		$	—		$	—
Derivative Contracts:
Energy-Related Contracts (B)	$	137		$	(662	)	$	19		$	770		$	10
NDT Fund (C)
Equity Securities	$	1,151		$	—		$	1,150		$	1		$	—
Debt Securities—U.S. Treasury	$	225		$	—		$	—		$	225		$	—
Debt Securities—Govt Other	$	352		$	—		$	—		$	352		$	—
Debt Securities—Corporate	$	486		$	—		$	—		$	486		$	—
Rabbi Trust (C)
Equity Securities	$	28		$	—		$	28		$	—		$	—
Debt Securities—U.S. Treasury	$	57		$	—		$	—		$	57		$	—
Debt Securities—Govt Other	$	47		$	—		$	—		$	47		$	—
Debt Securities—Corporate	$	114		$	—		$	—		$	114		$	—
Liabilities:
Derivative Contracts:
Energy-Related Contracts (B)	$	(32	)	$	660		$	(43	)	$	(646	)	$	(3	)
Interest Rate Swaps (D)	$	(5	)	$	—		$	—		$	(5	)	$	—
PSE&G
Assets:
Rabbi Trust (C)
Equity Securities	$	5		$	—		$	5		$	—		$	—
Debt Securities—U.S. Treasury	$	11		$	—		$	—		$	11		$	—
Debt Securities—Govt Other	$	9		$	—		$	—		$	9		$	—
Debt Securities—Corporate	$	23		$	—		$	—		$	23		$	—
PSEG Power
Assets:
Derivative Contracts:
Energy-Related Contracts (B)	$	137		$	(662	)	$	19		$	770		$	10
NDT Fund (C)
Equity Securities	$	1,151		$	—		$	1,150		$	1		$	—
Debt Securities—U.S. Treasury	$	225		$	—		$	—		$	225		$	—
Debt Securities—Govt Other	$	352		$	—		$	—		$	352		$	—
Debt Securities—Corporate	$	486		$	—		$	—		$	486		$	—
Rabbi Trust (C)
Equity Securities	$	8		$	—		$	8		$	—		$	—
Debt Securities—U.S. Treasury	$	14		$	—		$	—		$	14		$	—
Debt Securities—Govt Other	$	12		$	—		$	—		$	12		$	—
Debt Securities—Corporate	$	28		$	—		$	—		$	28		$	—
Liabilities:
Derivative Contracts:
Energy-Related Contracts (B)	$	(32	)	$	660		$	(43	)	$	(646	)	$	(3	)

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	Recurring Fair Value Measurements as of December 31, 2018
Description	Total			Netting (E)			Quoted Market Prices for Identical Assets (Level 1)			Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
	Millions
PSEG
Assets:
Cash Equivalents (A)	$	100		$	—		$	100		$	—		$	—
Derivative Contracts:
Energy-Related Contracts (B)	$	12		$	(551	)	$	29		$	527		$	7
NDT Fund (C)
Equity Securities	$	900		$	—		$	898		$	2		$	—
Debt Securities—U.S. Treasury	$	171		$	—		$	—		$	171		$	—
Debt Securities—Govt Other	$	320		$	—		$	—		$	320		$	—
Debt Securities—Corporate	$	487		$	—		$	—		$	487		$	—
Rabbi Trust (C)
Equity Securities	$	23		$	—		$	23		$	—		$	—
Debt Securities—U.S. Treasury	$	69		$	—		$	—		$	69		$	—
Debt Securities—Govt Other	$	40		$	—		$	—		$	40		$	—
Debt Securities—Corporate	$	92		$	—		$	—		$	92		$	—
Liabilities:
Derivative Contracts:
Energy-Related Contracts (B)	$	(15	)	$	704		$	(36	)	$	(677	)	$	(6	)
PSE&G
Assets:
Rabbi Trust (C)
Equity Securities	$	5		$	—		$	5		$	—		$	—
Debt Securities—U.S. Treasury	$	14		$	—		$	—		$	14		$	—
Debt Securities—Govt Other	$	8		$	—		$	—		$	8		$	—
Debt Securities—Corporate	$	18		$	—		$	—		$	18		$	—
PSEG Power
Assets:
Derivative Contracts:
Energy-Related Contracts (B)	$	12		$	(551	)	$	29		$	527		$	7
NDT Fund (C)
Equity Securities	$	900		$	—		$	898		$	2		$	—
Debt Securities—U.S. Treasury	$	171		$	—		$	—		$	171		$	—
Debt Securities—Govt Other	$	320		$	—		$	—		$	320		$	—
Debt Securities—Corporate	$	487		$	—		$	—		$	487		$	—
Rabbi Trust (C)
Equity Securities	$	6		$	—		$	6		$	—		$	—
Debt Securities—U.S. Treasury	$	17		$	—		$	—		$	17		$	—
Debt Securities—Govt Other	$	10		$	—		$	—		$	10		$	—
Debt Securities—Corporate	$	23		$	—		$	—		$	23		$	—
Liabilities:
Derivative Contracts:
Energy-Related Contracts (B)	$	(15	)	$	704		$	(36	)	$	(677	)	$	(6	)


(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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on settled pricing inputs which come directly from the exchange.

Level 2—Fair values for energy-related contracts are obtained primarily using a market-based approach. Most derivative contracts (forward purchase or sale contracts and swaps) are valued using settled prices from similar assets and liabilities from an exchange, such as NYMEX, ICE and Nodal Exchange, or auction prices. Prices used in the valuation process are also corroborated independently by management to determine that values are based on actual transaction data or, in the absence of transactions, bid and offers for the day. Examples may include certain exchange and non-exchange traded capacity and electricity contracts and natural gas physical or swap contracts based on market prices, basis adjustments and other premiums where adjustments and premiums are not considered significant to the overall inputs.

Level 3—Unobservable inputs are used for the valuation of certain contracts. See “Additional Information Regarding Level 3 Measurements” below for more information on the utilization of unobservable inputs.

(C)

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

Level 1—Investments in marketable equity securities within the NDT Fund are primarily investments in common stocks across a broad range of industries and sectors. Most equity securities are priced utilizing the principal market close price or, in some cases, midpoint, bid or ask price. Certain other equity securities in the NDT and Rabbi Trust Funds consist primarily of investments in money market funds which seek a high level of current income as is consistent with the preservation of capital and the maintenance of liquidity. To pursue its goals, the funds normally invest in diversified portfolios of high quality, short-term, dollar-denominated debt securities and government securities. The funds’ net asset value is priced and published daily. The Rabbi Trust’s Russell 3000 index fund is valued based on quoted prices in an active market and can be redeemed daily without restriction.

Level 2—NDT and Rabbi Trust fixed income securities include investment grade corporate bonds, collateralized mortgage obligations, asset-backed securities and certain government and U.S. Treasury obligations or Federal Agency asset-backed securities and municipal bonds with a wide range of maturities. Since many fixed income securities do not trade on a daily basis, they are priced using an evaluated pricing methodology that varies by asset class and reflects observable market information such as the most recent exchange price or quoted bid for similar securities. Market-based standard inputs typically include benchmark yields, reported trades, broker/dealer quotes and issuer spreads. The preferred stocks are not actively traded on a daily basis and therefore, are also priced using an evaluated pricing methodology. Certain short-term investments are valued using observable market prices or market parameters such as time-to-maturity, coupon rate, quality rating and current yield.


(D)	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.

Additional Information Regarding Level 3 Measurements

For valuations that include both observable and unobservable inputs, if the unobservable input is determined to be significant to the overall inputs, the entire valuation is categorized in Level 3. This includes derivatives valued using indicative price quotations for contracts with tenors that extend into periods with no observable pricing. In instances where observable data is unavailable, consideration is given to the assumptions that market participants would use in valuing the asset or liability. This includes assumptions about market risks such as liquidity, volatility and contract duration. Such instruments are categorized in Level 3 because the model inputs generally are not observable. PSEG’s Risk Management Committee (RMC) approves risk management policies and objectives for risk assessment, control and valuation, counterparty credit approval and the monitoring and reporting of risk exposures. The RMC reports to the Corporate Governance and Audit Committees of the PSEG Board on the scope of the risk management activities and is responsible for approving all valuation procedures at PSEG. Forward price curves for the power market utilized by PSEG Power to manage the portfolio are maintained and reviewed by PSEG’s Enterprise Risk Management market pricing group and used for financial reporting purposes. PSEG considers credit and nonperformance risk in the valuation of derivative contracts categorized in Levels 2 and 3, including both historical and current market data, in its assessment of credit and nonperformance risk by counterparty. The impacts of credit and nonperformance risk were not material to the financial statements.

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The fair value of PSEG Power’s electric load contracts in which load consumption may change hourly based on demand are measured using certain unobservable inputs, such as historic load variability and, accordingly, are categorized as Level 3. The fair value of PSEG Power’s gas physical contracts at certain illiquid delivery locations are measured using average historical basis and, accordingly, are categorized as Level 3. While these physical gas contracts have an unobservable component in their respective forward price curves, the fluctuations in fair value have been driven primarily by changes in the observable inputs. The following tables provide details surrounding significant Level 3 valuations as of December 31, 2019 and 2018.

Quantitative Information About Level 3 Fair Value Measurements

Commodity

Level 3 Position

Fair Value as of December 31, 2019

Valuation

Technique(s)

Significant

Unobservable Input

Range

Assets

(Liabilities)

Millions

PSEG Power

Electricity

Electric Load Contracts

—

Discounted Cash flow

Historic Load Variability

0% to 10%

Gas

Gas Physical Contracts

—

)

Discounted Cash flow

Average Historical Basis

-50% to 0%

Total PSEG and PSEG Power

)

Quantitative Information About Level 3 Fair Value Measurements

Commodity

Level 3 Position

Fair Value as of December 31, 2018

Valuation

Technique(s)

Significant

Unobservable Input

Range

Assets

(Liabilities)

Millions

PSEG Power

Electricity

Electric Load Contracts

)

Discounted Cash flow

Historic Load Variability

0% to 15%

Gas

Gas Physical Contracts

)

Discounted Cash flow

Average Historical Basis

-40% to 0%

Total PSEG and PSEG Power

)

Significant unobservable inputs listed above would have a direct impact on the fair values of the above Level 3 instruments if they were adjusted. For energy-related contracts in cases where PSEG Power is a seller, an increase in the load variability would decrease the fair value. For gas-related contracts in cases where PSEG Power is a buyer, an increase in the average historical basis would increase the fair value.

A reconciliation of the beginning and ending balances of Level 3 derivative contracts and securities for the years ended December 31, 2019 and 2018, respectively, follows:

Changes in Level 3 Assets and (Liabilities) Measured at Fair Value on a Recurring Basis

for the Year Ended December 31, 2019




Description	Balance as of December 31, 2018		Total Gains or (Losses) Realized/Unrealized Included in Income (A)		Purchases, (Sales)		Issuances/ Settlements (B)			Transfers In/Out (C)		Balance as of December 31, 2019

PSEG and PSEG Power
Net Derivative Assets (Liabilities)	$	1	$	14	$	—	$	(8	)	$	—	$	7

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Changes in Level 3 Assets and (Liabilities) Measured at Fair Value on a Recurring Basis

for the Year Ended December 31, 2018




Description	Balance as of December 31, 2017		Total Gains or (Losses) Realized/Unrealized Included in Income (A)			Purchases, (Sales)		Issuances/ Settlements (B)		Transfers In/Out (C)		Balance as of December 31, 2018
	Millions
PSEG and PSEG Power
Net Derivative Assets (Liabilities)	$	7	$	(6	)	$	—	$	—	$	—	$	1

(A)Unrealized gains (losses) in the following table represent the change in derivative assets and liabilities still held as of December 31, 2019 and 2018.




	Years Ended December 31,
	2019						2018
	Total Gains (Losses)			Unrealized Gains (Losses)			Total Gains (Losses)			Unrealized Gains (Losses)
	Millions
PSEG and PSEG Power
Operating Revenues	$	23		$	12		$	(2	)	$	—
Energy Costs	(9		)	(6		)	(4		)	(6		)
Total	$	14		$	6		$	(6	)	$	(6	)


(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.

As of December 31, 2019, PSEG carried $2.6 billion of net assets that are measured at fair value on a recurring basis, of which $7 million of net assets were measured using unobservable inputs and classified as Level 3 within the fair value hierarchy.

As of December 31, 2018, PSEG carried $2.2 billion of net assets that are measured at fair value on a recurring basis, of which $1 million of net assets were measured using unobservable inputs and classified as Level 3 within the fair value hierarchy.

Note 20. Stock Based Compensation

PSEG’s Amended and Restated 2004 Long-Term Incentive Plan (LTIP) is a broad-based equity compensation program that provides for grants of various long-term incentive compensation awards, such as stock options, stock appreciation rights, performance share units, restricted stock, restricted stock units, cash awards or any combination thereof. The types of long-term incentive awards that have been granted under the LTIP are non-qualified options to purchase shares of PSEG’s common stock, restricted stock unit awards and performance share unit awards. The type of equity award that is granted and the details of that award may vary from time to time and is subject to the approval of the Organization and Compensation Committee of PSEG’s Board of Directors (O&CC), the LTIP’s administrative committee.

The LTIP currently provides for the issuance of equity awards with respect to approximately 16 million shares of common stock. As of December 31, 2019, there were approximately 12 million shares available for future awards under the LTIP.

Stock Options

Under the LTIP, non-qualified options to acquire shares of PSEG common stock may be granted to officers and other key employees selected by the O&CC. Option awards are granted with an exercise price equal to the market price of PSEG’s common stock at the grant date. The options generally vest over four years of continuous service. Vesting schedules may be accelerated upon the occurrence of certain events, such as a change-in-control (unless substituted with an equity award of equal value), retirement, death or disability. Options are exercisable over a period of time designated by the O&CC (but not prior to one year or longer than ten years from the date of grant) and are subject to such other terms and conditions as the O&CC determines. Payment by option holders upon exercise of an option may be made in cash or, with the consent of the O&CC, by delivering previously acquired shares of PSEG common stock. No options have been granted since 2009.

Restricted Stock Units (RSUs)

Under the LTIP, PSEG has granted RSU awards to officers and other key employees. These awards, which are bookkeeping entries only, are subject to risk of forfeiture until vested by continued employment. Until distributed, the units are credited with

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dividend equivalent units (DEUs) proportionate to the dividends paid on PSEG common stock. Distributions are made in shares of common stock. The RSU grants for 2019 and 2018 generally vest at the end of three years. Vesting may be accelerated (pro-rated basis or full vesting) upon certain events such as change-in-control, retirement, disability or death.

Performance Share Units (PSUs)

Under the LTIP, PSEG has granted PSUs to officers and other key employees. These provide for distribution in shares of PSEG common stock based on achievement of certain financial goals over a three-year performance period. Following the end of the performance period, the payout varies from 0% to 200% of the number of PSUs granted depending on PSEG’s performance with respect to certain financial targets, including targets related to comparative performance against other companies in a peer group of energy companies. The PSUs are credited with DEUs proportionate to the dividends paid on PSEG common stock. Distributions are made in shares of common stock. Vesting may be accelerated on a pro-rated basis for the period of the employee’s service during the performance period as a result of certain events, such as change-in-control, retirement, death or disability.

Stock-Based Compensation

PSEG recognizes compensation expense for stock options based on their grant date fair values, which are determined using the Black-Scholes option-pricing model. Stock option awards are expensed on a tranche-specific basis over the requisite service period of the award. Ultimately, compensation expense for stock options is recognized for awards that vest.

PSEG recognizes compensation expense for RSUs over the vesting period based on the grant date fair value of the shares, which is equal to the closing market price of PSEG’s common stock on the date of the grant.

PSEG recognizes compensation expense for the total shareholder return (TSR) target for its PSU awards based on the grant date fair values of the award, which are determined using the Monte Carlo model. The following table provides the assumptions used to calculate the grant date fair value of the TSR portion of the PSU awards for 2019, 2018 and 2017:




Grant Date	Risk-Free Interest Rate	Volatility

February 19, 2019	2.47%	16.74%
February 20, 2018	2.36%	17.57%
February 21, 2017	1.50%	20.00%

The accrual of compensation cost is based on the probable achievement of the performance conditions, which result in a payout from 0% to 200% of the initial grant. PSEG recognizes compensation expense for the return on invested capital target for its PSUs based on the grant date fair value of the awards, which is equal to the market price of PSEG’s common stock on the date of the grant. The accrual during the year of grant is estimated at 100% of the original grant. Such accrual may be adjusted to reflect the actual outcome.




	2019		2018		2017
	Millions
Compensation Cost included in Operation and Maintenance Expense	$	33	$	30	$	31
Income Tax Benefit Recognized in Consolidated Statement of Operations	$	9	$	9	$	13

For 2019, 2018 and 2017, PSEG also recorded excess tax benefit of $5 million, $3 million and $4 million, respectively.

PSEG recognizes compensation cost of awards issued over the shorter of the original vesting period or the period beginning on the date of grant and ending on the date an individual is eligible for retirement and the award vests.

Stock Options

As of January 1, 2019, there were 231,933 stock options outstanding, all of which were exercised in 2019 at a weighted average price of $33.49. There were no stock options granted or vested in 2019, 2018 and 2017.

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Activity for options exercised for the years ended December 31, 2019, 2018 and 2017 is shown below:




	2019		2018		2017
	Millions
Total Intrinsic Value of Options Exercised	$	5	$	2	$	5
Cash Received from Options Exercised	$	8	$	4	$	26
Tax Benefit Realized from Options Exercised	$	1	$	—	$	—

RSUs

Changes in RSUs for the year ended December 31, 2019 are summarized as follows:




	Shares	Weighted Average Grant Date Fair Value		Weighted Average Remaining Years Contractual Term	Aggregate Intrinsic Value
Non-vested as of January 1, 2019	257,583	$	46.58
Granted	200,923	$	56.24
Vested	207,126	$	51.34
Canceled/Forfeited	36,399	$	50.23
Non-vested as of December 31, 2019	214,981	$	50.41	1.1	$	12,694,628

The weighted average grant date fair value per share for RSUs during the years ended December 31, 2019, 2018 and 2017 was $56.24, $49.34 and $44.33 per share, respectively.

The total intrinsic value of RSUs distributed during the years ended December 31, 2019, 2018 and 2017 was $16 million, $12 million and $13 million, respectively.

As of December 31, 2019, there was approximately $4 million of unrecognized compensation cost related to the RSUs, which is expected to be recognized over a weighted average period of one year. DEUs of 21,535 accrued on the RSUs during the year.

PSUs

Changes in PSUs for the year ended December 31, 2019 are summarized as follows:




	Shares	Weighted Average Grant Date Fair Value		Weighted Average Remaining Years Contractual Term	Aggregate Intrinsic Value
Non-vested as of January 1, 2019	377,541	$	51.94
Granted	320,078	$	62.17
Vested	299,201	$	54.10
Canceled/Forfeited	63,903	$	54.52
Non-vested as of December 31, 2019	334,515	$	59.30	1.6	$	19,753,111

The weighted average grant date fair value per share for PSUs during the years ended December 31, 2019, 2018 and 2017 was $62.17, $54.95 and $45.02 per share, respectively.

The total intrinsic value of PSUs distributed during the years ended December 31, 2019, 2018 and 2017 was $17 million, $17 million and $18 million, respectively.

As of December 31, 2019, there was approximately $20 million of unrecognized compensation cost related to the PSUs, which is expected to be recognized over a weighted average period of 1.6 years. DEUs of 33,351 accrued on the PSUs during the year.

Outside Directors

Under the Directors Equity Plan, annually, on the first business day of May, each non-employee member of the Board of Directors is awarded stock units based on the amount of annual compensation to be paid at the closing price of PSEG common stock on that date. DEUs are credited quarterly and distributions will commence upon the director leaving the Board as specified by him/her in accordance with the provisions of the Directors Equity Plan.

The fair value of these awards is recorded as compensation expense in the Consolidated Statements of Operations. Compensation expense for the plan was immaterial for each of the years ended December 31, 2019, 2018 and 2017.

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Employee Stock Purchase Plan (ESPP)

PSEG maintains an ESPP for all eligible employees of PSEG and its subsidiaries. Under the ESPP, shares of PSEG common stock may be purchased at 95% of the fair market value for represented employees and 90% for non-represented employees through payroll deductions. Dividends had been reinvested for all employees at 95% of the fair market price unless the participant elected to receive a cash dividend. Effective October 1, 2019, dividends are to be paid out in cash unless the participant elects the dividends to be reinvested at fair market price. All employees are required to hold the shares purchased under the ESPP for at least three months from the purchase date. In any year, employees may purchase shares having a value not exceeding 10% of their base pay. Compensation expense recognized under this program was $1 million for December 31, 2019, and immaterial for each of the years ended December 31, 2018 and 2017.

During the years ended December 31, 2019, 2018 and 2017, employees purchased 280,077 shares, 286,559 shares and 288,527 shares, respectively, at an average price of $54.67, $47.44 and $42.07 per share, respectively. As of December 31, 2019, 2.6 million shares were available for future issuance under this plan.

Note 21. Other Income (Deductions)




	PSE&G			PSEG Power			Other (A)			Consolidated Total
	Millions
Year Ended December 31, 2019
NDT Fund Interest and Dividends	$	—		$	57		$	—		$	57
Allowance for Funds Used During Construction	59			—			—			59
Solar Loan Interest	16			—			—			16
Donations	—			—			(11		)	(11		)
Other	8			(3		)	(1		)	4
Total Other Income (Deductions)	$	83		$	54		$	(12	)	$	125
Year Ended December 31, 2018
NDT Fund Interest and Dividends	$	—		$	52		$	—		$	52
Allowance for Funds Used During Construction	54			—			—			54
Solar Loan Interest	18			—			—			18
Donations	—			—			(17		)	(17		)
Other	8			(31		)	1			(22		)
Total Other Income (Deductions)	$	80		$	21		$	(16	)	$	85
Year Ended December 31, 2017
NDT Fund Interest and Dividends	$	—		$	45		$	—		$	45
Allowance for Funds Used During Construction	56			—			—			56
Solar Loan Interest	21			—			—			21
Donations	(1		)	(2		)	(25		)	(28		)
Other	9			(23		)	2			(12		)
Total Other Income (Deductions)	$	85		$	20		$	(23	)	$	82


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

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Note 22. Income Taxes

A reconciliation of reported income tax expense for PSEG with the amount computed by multiplying pre-tax income by the statutory federal income tax rate of 21% in 2019 and 2018 and 35% in 2017 is as follows:




	Years Ended December 31,
PSEG	2019			2018			2017
	Millions
Net Income	$	1,693		$	1,438		$	1,574
Income Taxes:
Operating Income:
Current (Benefit) Expense:
Federal	$	84		$	(97	)	$	86
State	18			83			(31		)
Total Current	102			(14		)	55
Deferred Expense (Benefit):
Federal	3			373			(482		)
State	132			71			92
Total Deferred	135			444			(390		)
Investment Tax Credit (ITC)	20			(13		)	29
Total Income Tax Expense (Benefit)	$	257		$	417		$	(306	)
Pre-Tax Income	$	1,950		$	1,855		$	1,268
Tax Computed at Statutory Rate @ 21% in 2019 and 2018 and 35% in 2017	$	410		$	390		$	444
Increase (Decrease) Attributable to Flow-Through of Certain Tax Adjustments:
State Income Taxes (net of federal income tax)	117			123			36
Uncertain Tax Positions	—			(24		)	(3		)
Manufacturing Deduction	—			—			(13		)
NDT Fund	34			(13		)	19
Plant-Related Items	(2		)	(10		)	(23		)
Tax Credits	(18		)	(16		)	(22		)
Audit Settlement	—			—			6
Tax Adjustment Credit	(272		)	(30		)	—
Deferred Tax Expense (Benefit) - Tax Act	—			3			(755		)
Other	(12		)	(6		)	5
Subtotal	(153		)	27			(750		)
Total Income Tax Expense (Benefit)	$	257		$	417		$	(306	)
Effective Income Tax Rate	13.2		%	22.5		%	(24.1		)%

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The following is an analysis of deferred income taxes for PSEG:




	As of December 31,
PSEG	2019		2018
	Millions
Deferred Income Taxes
Assets:
Noncurrent
Regulatory Liability Excess Deferred Tax	$	539	$	606
OPEB	151		163
Related to Uncertain Tax Positions	97		71
Interest Disallowance Carry Forward	76		—
Operating Leases	64		—
Other	128		—
Total Noncurrent Assets	$	1,055	$	840

Liabilities:
Noncurrent:
Plant-Related Items	$	5,051	$	4,817
New Jersey Corporate Business Tax	876		756
Leasing Activities	284		307
AROs and NDT Fund	277		196
Taxes Recoverable Through Future Rates (net)	108		89
Pension Costs	98		111
Operating Leases	59		—
Other	273		12
Total Noncurrent Liabilities	$	7,026	$	6,288
Summary of Accumulated Deferred Income Taxes:
Net Noncurrent Deferred Income Tax Liabilities	$	5,971	$	5,448
ITC	285		265
Net Total Noncurrent Deferred Income Taxes and ITC	$	6,256	$	5,713

The deferred tax effect of certain assets and liabilities is presented in the table above net of the deferred tax effect associated with the respective regulatory deferrals.

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A reconciliation of reported income tax expense for PSE&G with the amount computed by multiplying pre-tax income by the statutory federal income tax rate of 21% in 2019 and 2018 and 35% in 2017 is as follows:




	Years Ended December 31,
PSE&G	2019			2018			2017
	Millions
Net Income	$	1,250		$	1,067		$	973
Income Taxes:
Operating Income:
Current (Benefit) Expense:
Federal	$	121		$	(62	)	$	(52	)
State	—			1			(1		)
Total Current	121			(61		)	(53		)
Deferred Expense (Benefit):
Federal	(156		)	287			492
State	117			122			129
Total Deferred	(39		)	409			621
ITC	11			(4		)	(5		)
Total Income Tax Expense	$	93		$	344		$	563
Pre-Tax Income	$	1,343		$	1,411		$	1,536
Tax Computed at Statutory Rate @ 21% in 2019 and 2018 and 35% in 2017	$	282		$	296		$	538
Increase (Decrease) Attributable to Flow-Through of Certain Tax Adjustments:
State Income Taxes (net of federal income tax)	92			98			83
Uncertain Tax Positions	1			(1		)	(9		)
Plant-Related Items	(2		)	(10		)	(23		)
Tax Credits	(8		)	(8		)	(9		)
Tax Adjustment Credit	(272		)	(30		)	—
Deferred Tax Benefit - Tax Act	—			—			(10		)
Other	—			(1		)	(7		)
Subtotal	(189		)	48			25
Total Income Tax Expense	$	93		$	344		$	563
Effective Income Tax Rate	6.9		%	24.4		%	36.7		%

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The following is an analysis of deferred income taxes for PSE&G:




	As of December 31,
PSE&G	2019		2018
	Millions
Deferred Income Taxes
Assets:
Noncurrent:
Regulatory Liability Excess Deferred Tax	$	539	$	606
OPEB	97		114
Related to Uncertain Tax Positions	42		—
Operating Leases	21		—
Other	55		—
Total Noncurrent Assets	$	754	$	720
Liabilities:
Noncurrent:
Plant-Related Items	$	3,754	$	3,622
New Jersey Corporate Business Tax	588		486
Pension Costs	160		159
Taxes Recoverable Through Future Rates (net)	108		89
Conservation Costs	44		36
Operating Leases	21		—
Other	183		84
Total Noncurrent Liabilities	$	4,858	$	4,476
Summary of Accumulated Deferred Income Taxes:
Net Noncurrent Deferred Income Tax Liabilities	$	4,104	$	3,756
ITC	85		74
Net Total Noncurrent Deferred Income Taxes and ITC	$	4,189	$	3,830

The deferred tax effect of certain assets and liabilities is presented in the table above net of the deferred tax effect associated with the respective regulatory deferrals.

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A reconciliation of reported income tax expense for PSEG Power with the amount computed by multiplying pre-tax income by the statutory federal income tax rate of 21% in 2019 and 2018 and 35% in 2017 is as follows:




	Years Ended December 31,
PSEG Power	2019			2018			2017
	Millions
Net Income	$	468		$	365		$	479
Income Taxes:
Operating Income:
Current (Benefit) Expense:
Federal	$	(48	)	$	(164	)	$	95
State	3			24			(17		)
Total Current	(45		)	(140		)	78
Deferred Expense (Benefit):
Federal	208			214			(804		)
State	31			1			(37		)
Total Deferred	239			215			(841		)
ITC	9			(9		)	34
Total Income Tax Expense (Benefit)	$	203		$	66		$	(729	)
Pre-Tax Income (Loss)	$	671		$	431		$	(250	)
Tax Computed at Statutory Rate @ 21% in 2019 and 2018 and 35% in 2017	$	141		$	91		$	(88	)
Increase (Decrease) Attributable to Flow-Through of Certain Tax Adjustments:
State Income Taxes (net of federal income tax)	25			21			(36		)
Manufacturing Deduction	—			—			(13		)
NDT Fund	34			(13		)	19
Tax Credits	(10		)	(7		)	(12		)
Related to Uncertain Tax Positions	11			(24		)	7
Audit Settlement	—			—			1
Deferred Tax Benefit - Tax Act	—			(1		)	(610		)
Other	2			(1		)	3
Subtotal	62			(25		)	(641		)
Total Income Tax Expense (Benefit)	$	203		$	66		$	(729	)
Effective Income Tax Rate	30.3		%	15.3		%	291.6		%

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The following is an analysis of deferred income taxes for PSEG Power:




	As of December 31,
PSEG Power	2019		2018
	Millions
Deferred Income Taxes
Assets:
Noncurrent:
Related to Uncertain Tax Positions	$	72	$	60
Pension Costs	61		52
OPEB	40		37
Operating Leases	15		—
Interest Disallowance Carry Forward	12		—
Contractual Liabilities & Environmental Costs	7		9
Other	30		61
Total Noncurrent Assets	$	237	$	219
Liabilities:
Noncurrent:
Plant-Related Items	$	1,292	$	1,189
New Jersey Corporate Business Tax	282		260
AROs and NDT Fund	278		197
Operating Leases	15		—
Other	45		—
Total Noncurrent Liabilities	$	1,912	$	1,646
Summary of Accumulated Deferred Income Taxes:
Net Noncurrent Deferred Income Tax Liabilities	$	1,675	$	1,427
ITC	201		192
Net Total Noncurrent Deferred Income Taxes and ITC	$	1,876	$	1,619

PSEG, PSE&G and PSEG Power each provide deferred taxes at the enacted statutory tax rate for all temporary differences between the financial statement carrying amounts and the tax bases of assets and liabilities irrespective of the treatment for rate-making purposes. Management believes that it is probable that the accumulated tax benefits that previously have been treated as a flow-through item to PSE&G customers will be recovered from or refunded to PSE&G’s customers in the future. See Note 7. Regulatory Assets and Liabilities.

Effective January 1, 2018, the U.S. federal corporate income tax rate was reduced from a maximum of 35% to 21% resulting in a decrease in PSEG’s, PSE&G’s and PSEG Power’s effective income tax rates. To the extent allowed under the Tax Act, PSEG Power’s operating cash flows reflect the full expensing of qualifying capital investments for income tax purposes. The impact of the lower federal income tax rate on PSE&G was reflected in PSE&G’s 2018 distribution base rate proceeding and its 2018 transmission rate filing. The distribution base rate proceeding established a TAC mechanism that provides for the refund to customers of the excess deferred income tax regulatory liabilities as well as the flowback of previously realized and current period deferred income taxes related to tax repair deductions. The accounting for the TAC mechanism results in lower revenues and lower tax expense and a current effective tax rate for PSEG and PSE&G that is significantly lower than the statutory rate.

The decrease in the federal tax rate resulted in PSE&G recording excess deferred income taxes of approximately $2.1 billion and a Regulatory Liability of approximately $2.9 billion as of December 31, 2018. In 2019, PSE&G returned approximately $380 million of excess deferred income taxes and previously realized and current period deferred income taxes related to tax repair deductions to its customers with a reduction to tax expense of approximately $272 million. The flowback to customers of the excess deferred income taxes and previously realized tax repair deductions resulted in a decrease of approximately $321 million in the Regulatory Liability. The current period tax repair deduction reduces tax expense and revenue and recognizes a Regulatory Asset as PSE&G believes it is probable that the current period tax repair deductions flowed through to the customers will be recovered from customers in the future. See Note 7. Regulatory Assets and Liabilities for additional information.

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The Tax Act is generally expected to result in lower operating cash flows for PSE&G resulting from the elimination of bonus depreciation, partially offset by higher revenues due to the higher rate base.

In November 2018, the IRS issued proposed regulations addressing the interest disallowance rules contained in the Tax Act. For non-regulated businesses, these rules set a cap on the amount of interest that can be deducted in a given year. Any amount that is disallowed can be carried forward indefinitely. For 2018 and 2019, a portion of PSEG’s and PSEG Power’s interest expense was disallowed for tax purposes but it is anticipated that these amounts will be realized in future periods. However, certain aspects of the proposed regulations are unclear. PSEG recorded taxes based on its interpretation of the relevant statutes.

In September 2019, the IRS released final and additional proposed regulations regarding the application of tax depreciation rules as amended by the Tax Act. PSEG, PSE&G and PSEG Power do not believe the final or proposed regulations will materially impact their respective financial statements.

Amounts recorded under the Tax Act, including but not limited to depreciation and interest disallowance, are subject to change based on several factors, including but not limited to, the IRS and state taxing authorities issuing additional guidance and/or further clarification. Any further guidance or clarification could impact PSEG’s, PSE&G’s and PSEG Power’s financial statements.

In 2019, PSE&G generated a $16 million New Jersey Corporate Business Tax NOL that is expected to be fully realized in the future. There are no other material tax carryforwards in other jurisdictions.

PSEG recorded the following amounts related to its unrecognized tax benefits, which were primarily comprised of amounts recorded for PSE&G, PSEG Power and Energy Holdings:




2019	PSEG			PSE&G			PSEG Power			Energy Holdings
	Millions
Total Amount of Unrecognized Tax Benefits as of January 1, 2019	$	318		$	108		$	151		$	54
Increases as a Result of Positions Taken in a Prior Period	17			5			8			5
Decreases as a Result of Positions Taken in a Prior Period	(37		)	(1		)	(13		)	(22		)
Increases as a Result of Positions Taken during the Current Period	27			12			15			—
Decreases as a Result of Positions Taken during the Current Period	—			—			—			—
Decreases as a Result of Settlements with Taxing Authorities	(4		)	—			—			(4		)
Decreases due to Lapses of Applicable Statute of Limitations	—			—			—			—
Total Amount of Unrecognized Tax Benefits as of December 31, 2019	$	321		$	124		$	161		$	33
Accumulated Deferred Income Taxes Associated with Unrecognized Tax Benefits	(184		)	(71		)	(105		)	(7		)
Regulatory Asset—Unrecognized Tax Benefits	(46		)	(46		)	—			—
Total Amount of Unrecognized Tax Benefits that if Recognized, would Impact the Effective Tax Rate (including Interest and Penalties)	$	91		$	7		$	56		$	26




2018	PSEG			PSE&G			PSEG Power			Energy Holdings
	Millions
Total Amount of Unrecognized Tax Benefits as of January 1, 2018	$	334		$	135		$	142		$	53
Increases as a Result of Positions Taken in a Prior Period	11			4			4			3
Decreases as a Result of Positions Taken in a Prior Period	(70		)	(31		)	(37		)	(2		)
Increases as a Result of Positions Taken during the Current Period	52			3			48			—
Decreases as a Result of Positions Taken during the Current Period	(3		)	(3		)	—			—
Decreases as a Result of Settlements with Taxing Authorities	(6		)	—			(6		)	—
Decreases due to Lapses of Applicable Statute of Limitations	—			—			—			—
Total Amount of Unrecognized Tax Benefits as of December 31, 2018	$	318		$	108		$	151		$	54
Accumulated Deferred Income Taxes Associated with Unrecognized Tax Benefits	(173		)	(57		)	(104		)	(12		)
Regulatory Asset—Unrecognized Tax Benefits	(46		)	(46		)	—			—
Total Amount of Unrecognized Tax Benefits that if Recognized, would Impact the Effective Tax Rate (including Interest and Penalties)	$	99		$	5		$	47		$	42

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2017	PSEG			PSE&G			PSEG Power			Energy Holdings
	Millions
Total Amount of Unrecognized Tax Benefits as of January 1, 2017	$	328		$	140		$	128		$	57
Increases as a Result of Positions Taken in a Prior Period	40			15			18			8
Decreases as a Result of Positions Taken in a Prior Period	(32		)	(11		)	(10		)	(13		)
Increases as a Result of Positions Taken during the Current Period	12			5			6			1
Decreases as a Result of Positions Taken during the Current Period	(1		)	(1		)	—			—
Decreases as a Result of Settlements with Taxing Authorities	—			—			—			—
Decreases due to Lapses of Applicable Statute of Limitations	(13		)	(13		)	—			—
Total Amount of Unrecognized Tax Benefits as of December 31, 2017	$	334		$	135		$	142		$	53
Accumulated Deferred Income Taxes Associated with Unrecognized Tax Benefits	(157		)	(73		)	(72		)	(12		)
Regulatory Asset—Unrecognized Tax Benefits	(56		)	(56		)	—			—
Total Amount of Unrecognized Tax Benefits that if Recognized, would Impact the Effective Tax Rate (including Interest and Penalties)	$	121		$	6		$	70		$	41

PSEG and its subsidiaries include accrued interest and penalties related to uncertain tax positions required to be recorded as Income Tax Expense in the Consolidated Statements of Operations. Accumulated interest and penalties that are recorded on the Consolidated Balance Sheets on uncertain tax positions were as follows:




	Accumulated Interest and Penalties on Uncertain Tax Positions as of December 31,
	2019		2018		2017
	Millions
PSEG	$	40	$	43	$	70
PSE&G	$	16	$	12	$	25
PSEG Power	$	12	$	9	$	24
Energy Holdings	$	13	$	22	$	21

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It is reasonably possible that total unrecognized tax benefits will significantly increase or decrease within the next twelve months due to either agreements with various taxing authorities upon audit, the expiration of the Statute of Limitations, or other pending tax matters. These potential increases or decreases are as follows:




Possible (Increase)/Decrease in Total Unrecognized Tax Benefits	Over the next 12 Months
	Millions
PSEG	$	190
PSE&G	$	107
PSEG Power	$	77

A description of income tax years that remain subject to examination by material jurisdictions, where an examination has not already concluded are:




	PSEG	PSE&G	PSEG Power
United States
Federal	2011-2018	N/A	N/A
New Jersey	2011-2018	2011-2018	N/A
Pennsylvania	2015-2018	2015-2018	N/A
Connecticut	2016-2018	N/A	N/A
Maryland	2016-2018	N/A	N/A
New York	2017-2018	N/A	N/A

New Jersey State Tax Reform

In July 2018, the State of New Jersey made changes to its income tax laws, including imposing a temporary surtax on allocated corporate taxable income of 2.5% effective January 1, 2018 and 2019 and 1.5% in 2020 and 2021, as well as requiring corporate taxpayers to file in a combined reporting group as defined under New Jersey law starting in 2019. Both provisions include an exemption for public utilities. PSEG believes PSE&G meets the definition of a public utility and, therefore, will not be impacted by the temporary surtax or be included in the combined reporting group.

The State of New Jersey issued further guidance regarding the temporary surtax and clarified that New Jersey net operating loss carryovers can be deducted in computing a taxpayer’s entire net income. This guidance has the effect of lowering or eliminating the temporary surtax.

There are certain aspects of the law that remain unclear. In particular, PSEG anticipates that the State of New Jersey will issue clarifying guidance regarding the combined reporting rules. Any further guidance or clarification could impact PSEG’s and PSEG Power’s financial statements.

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Note 23. Accumulated Other Comprehensive Income (Loss), Net of Tax




PSEG	Other Comprehensive Income (Loss)
Accumulated Other Comprehensive Income (Loss)	Cash Flow Hedges			Pension and OPEB Plans			Available-for -Sale Securities			Total
	Millions
Balance as of December 31, 2016	$	2		$	(398	)	$	133		$	(263	)
Other Comprehensive Income before Reclassifications	—			(32		)	109			77
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	(2		)	24			(65		)	(43		)
Net Current Period Other Comprehensive Income (Loss)	(2		)	(8		)	44			34
Balance as of December 31, 2017	$	—		$	(406	)	$	177		$	(229	)
Cumulative Effect Adjustment to Reclassify Unrealized Net Gains on Equity Investments to Retained Earnings	—			—			(176		)	(176		)
Current Period Other Comprehensive Income (Loss)
Other Comprehensive Income before Reclassifications	(1		)	17			(25		)	(9		)
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	—			29			8			37
Net Current Period Other Comprehensive Income (Loss)	(1		)	46			(17		)	28
Net Change in Accumulated Other Comprehensive Income (Loss)	(1		)	46			(193		)	(148		)
Balance as of December 31, 2018	$	(1	)	$	(360	)	$	(16	)	$	(377	)
Cumulative Effect Adjustment to Reclassify Stranded Tax Effects Resulting in the Change in the Federal Corporate Income Tax to Retained Earnings	—			(81		)	—			(81		)
Current Period Other Comprehensive Income (Loss)
Other Comprehensive Income before Reclassifications	(17		)	(70		)	49			(38		)
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	3			12			(8		)	7
Net Current Period Other Comprehensive Income (Loss)	(14		)	(58		)	41			(31		)
Net Change in Accumulated Other Comprehensive Income (Loss)	(14		)	(139		)	41			(112		)
Balance as of December 31, 2019	$	(15	)	$	(499	)	$	25		$	(489	)

PSEG Power	Other Comprehensive Income (Loss)
Accumulated Other Comprehensive Income (Loss)	Cash Flow Hedges			Pension and OPEB Plans			Available-for -Sale Securities			Total
	Millions
Balance as of December 31, 2016	$	—		$	(340	)	$	129		$	(211	)
Other Comprehensive Income before Reclassifications	—			(28		)	106			78
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	—			21			(60		)	(39		)
Net Current Period Other Comprehensive Income (Loss)	—			(7		)	46			39
Balance as of December 31, 2017	$	—		$	(347	)	$	175		$	(172	)
Cumulative Effect Adjustment to Reclassify Unrealized Net Gains on Equity Investments to Retained Earnings	—			—			(175		)	(175		)
Current Period Other Comprehensive Income (Loss)
Other Comprehensive Income before Reclassifications	—			16			(19		)	(3		)
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	—			25			6			31
Net Current Period Other Comprehensive Income (Loss)	—			41			(13		)	28
Net Change in Accumulated Other Comprehensive Income (Loss)	—			41			(188		)	(147		)
Balance as of December 31, 2018	$	—		$	(306	)	$	(13	)	$	(319	)
Cumulative Effect Adjustment to Reclassify Stranded Tax Effects Resulting in the Change in the Federal Corporate Income Tax to Retained Earnings	—			(69		)	—			(69		)
Current Period Other Comprehensive Income (Loss)
Other Comprehensive Income before Reclassifications	—			(55		)	38			(17		)
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	—			10			(6		)	4
Net Current Period Other Comprehensive Income (Loss)	—			(45		)	32			(13		)
Net Change in Accumulated Other Comprehensive Income (Loss)	—			(114		)	32			(82		)
Balance as of December 31, 2019	$	—		$	(420	)	$	19		$	(401	)

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PSEG		Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement
		Year Ended December 31, 2017
Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	Location of Pre-Tax Amount in Statement of Operations	Pre-Tax Amount			Tax (Expense) Benefit			After-Tax Amount
		Millions
Cash Flow Hedges
Interest Rate Swaps	Interest Expense	$	3		$	(1	)	$	2
Total Cash Flow Hedges		3			(1		)	2
Pension and OPEB Plans
Amortization of Prior Service (Cost) Credit	Non-Operating Pension and OPEB Credits (Costs)	10			(4		)	6
Amortization of Actuarial Loss	Non-Operating Pension and OPEB Credits (Costs)	(51		)	21			(30		)
Total Pension and OPEB Plans		(41		)	17			(24		)
Available-for-Sale Securities
Realized Gains (Losses) and Other-Than-Temporary Impairments (OTTI)	Net Gains (Losses) on Trust Investments	134			(69		)	65
Total Available-for-Sale Securities		134			(69		)	65
Total		$	96		$	(53	)	$	43

PSEG Power		Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement
		Year Ended December 31, 2017
Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	Location of Pre-Tax Amount in Statement of Operations	Pre-Tax Amount			Tax (Expense) Benefit			After-Tax Amount
		Millions
Pension and OPEB Plans
Amortization of Prior Service (Cost) Credit	Non-Operating Pension and OPEB Credits (Costs)	$	9		$	(4	)	$	5
Amortization of Actuarial Loss	Non-Operating Pension and OPEB Credits (Costs)	(44		)	18			(26		)
Total Pension and OPEB Plans		(35		)	14			(21		)
Available-for-Sale Securities
Realized Gains (Losses) and OTTI	Net Gains (Losses) on Trust Investments	125			(65		)	60
Total Available-for-Sale Securities		125			(65		)	60
Total		$	90		$	(51	)	$	39

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PSEG		Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement
		Year Ended December 31, 2018
Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	Location of Pre-Tax Amount in Statement of Operations	Pre-Tax Amount			Tax (Expense) Benefit			After-Tax Amount
		Millions
Pension and OPEB Plans
Amortization of Prior Service (Cost) Credit	Non-Operating Pension and OPEB Credits (Costs)	$	6		$	(2	)	$	4
Amortization of Actuarial Loss	Non-Operating Pension and OPEB Credits (Costs)	(47		)	14			(33		)
Total Pension and OPEB Plans		(41		)	12			(29		)
Available-for-Sale Securities
Realized Gains (Losses)	Net Gains (Losses) on Trust Investments	(13		)	5			(8		)
Total Available-for-Sale Securities		(13		)	5			(8		)
Total		$	(54	)	$	17		$	(37	)

PSEG Power		Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement
		Year Ended December 31, 2018
Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	Location of Pre-Tax Amount in Statement of Operations	Pre-Tax Amount			Tax (Expense) Benefit			After-Tax Amount
		Millions
Pension and OPEB Plans
Amortization of Prior Service (Cost) Credit	Non-Operating Pension and OPEB Credits (Costs)	$	5		$	(1	)	$	4
Amortization of Actuarial Loss	Non-Operating Pension and OPEB Credits (Costs)	(40		)	11			(29		)
Total Pension and OPEB Plans		(35		)	10			(25		)
Available-for-Sale Securities
Realized Gains (Losses)	Net Gains (Losses) on Trust Investments	(11		)	5			(6		)
Total Available-for-Sale Securities		(11		)	5			(6		)
Total		$	(46	)	$	15		$	(31	)

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PSEG		Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement
		Year Ended December 31, 2019
Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	Location of Pre-Tax Amount in Statement of Operations	Pre-Tax Amount			Tax (Expense) Benefit			After-Tax Amount
		Millions
Cash Flow Hedges
Interest Rate Swaps	Interest Expense	$	(4	)	$	1		$	(3	)
Total Cash Flow Hedges		(4		)	1			(3		)
Pension and OPEB Plans
Amortization of Prior Service (Cost) Credit	Non-Operating Pension and OPEB Credits (Costs)	26			(7		)	19
Amortization of Actuarial Loss	Non-Operating Pension and OPEB Credits (Costs)	(43		)	12			(31		)
Total Pension and OPEB Plans		(17		)	5			(12		)
Available-for-Sale Securities
Realized Gains (Losses)	Net Gains (Losses) on Trust Investments	13			(5		)	8
Total Available-for-Sale Securities		13			(5		)	8
Total		$	(8	)	$	1		$	(7	)

PSEG Power		Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement
		Year Ended December 31, 2019
Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	Location of Pre-Tax Amount in Statement of Operations	Pre-Tax Amount			Tax (Expense) Benefit			After-Tax Amount
		Millions
Pension and OPEB Plans
Amortization of Prior Service (Cost) Credit	Non-Operating Pension and OPEB Credits (Costs)	$	23		$	(7	)	$	16
Amortization of Actuarial Loss	Non-Operating Pension and OPEB Credits (Costs)	(36		)	10			(26		)
Total Pension and OPEB Plans		(13		)	3			(10		)
Available-for-Sale Securities
Realized Gains (Losses)	Net Gains (Losses) on Trust Investments	10			(4		)	6
Total Available-for-Sale Securities		10			(4		)	6
Total		$	(3	)	$	(1	)	$	(4	)

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Note 24. Earnings Per Share (EPS) and Dividends

EPS

Diluted EPS is calculated by dividing Net Income by the weighted average number of shares of common stock outstanding, including shares issuable upon exercise of stock options outstanding or vesting of restricted stock awards granted under PSEG’s stock compensation plans and upon payment of PSUs or RSUs. For additional information on PSEG’s stock compensation plans see Note 20. Stock Based Compensation. The following table shows the effect of these stock options, PSUs and RSUs on the weighted average number of shares outstanding used in calculating diluted EPS:




	Years Ended December 31,
	2019				2018				2017
	Basic		Diluted		Basic		Diluted		Basic		Diluted
EPS Numerator:
(Millions)
Net Income	$	1,693	$	1,693	$	1,438	$	1,438	$	1,574	$	1,574
EPS Denominator:
(Millions)
Weighted Average Common Shares Outstanding	504		504		504		504		505		505
Effect of Stock Based Compensation Awards	—		3		—		3		—		2
Total Shares	504		507		504		507		505		507
EPS:
Net Income	$	3.35	$	3.33	$	2.85	$	2.83	$	3.12	$	3.10

For additional information on all the types of long-term incentive awards, see Note 20. Stock Based Compensation.

Dividends




	Years Ended December 31,
Dividend Payments on Common Stock	2019		2018		2017
Per Share	$	1.88	$	1.80	$	1.72
in Millions	$	950	$	910	$	870

On February 18, 2020, PSEG’s Board of Directors approved a $0.49 per share common stock dividend for the first quarter of 2020.

Note 25. Financial Information by Business Segment

Basis of Organization

PSEG’s, PSE&G’s and PSEG Power’s operating segments were determined by management in accordance with GAAP. These segments were determined based on how management measures performance based on segment Net Income, as illustrated in the following table, and how resources are allocated to each business. PSEG’s reportable segments are PSE&G and PSEG Power. PSE&G and PSEG Power each represent a single reportable segment and therefore no separate segment information is provided for these Registrants.

PSE&G

PSE&G earns revenues from its tariffs, under which it provides electric transmission and electric and gas distribution services to residential, commercial and industrial customers in New Jersey. The rates charged for electric transmission are regulated by FERC while the rates charged for electric and gas distribution are regulated by the BPU. Revenues are also earned from several other activities such as solar investments, sundry sales, the appliance service business, wholesale transmission services and other miscellaneous services.

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PSEG Power

PSEG Power earns revenues by selling energy, capacity and ancillary services on a wholesale basis under contract to power marketers and to load-serving entities and by bidding energy, capacity and ancillary services into the markets for these products. A significant portion of PSEG Power’s revenue is obtained from the various ISOs in which PSEG Power operates. The ISOs act similarly to a clearing house for all of its members in that all revenues paid out are collected from market participants based on their consumption of energy and energy-related products. PSEG Power also enters into bilateral contracts for energy, capacity, FTRs, gas, emission allowances and other energy-related contracts to optimize the value of its portfolio of generating assets and its electric and gas supply obligations. In addition, PSEG Power’s Salem 1, Salem 2 and Hope Creek nuclear plants receive ZEC revenue from the EDCs in New Jersey including PSE&G.

Other

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




	PSE&G		PSEG Power		Other (A)			Eliminations (B)			Consolidated Total
	Millions
Year Ended December 31, 2019
Operating Revenues	$	6,625	$	4,385	$	549		$	(1,483	)	$	10,076
Depreciation and Amortization	837		377		34			—			1,248
Operating Income (Loss)	1,469		448		26			—			1,943
Income from Equity Method Investments	—		14		—			—			14
Interest Income	18		7		6			(5		)	26
Interest Expense	361		119		94			(5		)	569
Income (Loss) before Income Taxes	1,343		671		(64		)	—			1,950
Income Tax Expense (Benefit)	93		203		(39		)	—			257
Net Income (Loss) (C)	$	1,250	$	468	$	(25	)	$	—		$	1,693
Gross Additions to Long-Lived Assets	$	2,542	$	607	$	17		$	—		$	3,166
As of December 31, 2019
Total Assets	$	33,266	$	12,805	$	2,715		$	(1,056	)	$	47,730
Investments in Equity Method Subsidiaries	$	—	$	66	$	1		$	—		$	67




	PSE&G		PSEG Power		Other (A)		Eliminations (B)			Consolidated Total
	Millions
Year Ended December 31, 2018
Operating Revenues	$	6,471	$	4,146	$	571	$	(1,492	)	$	9,696
Depreciation and Amortization	770		354		34		—			1,158
Operating Income (Loss)	1,606		596		96		—			2,298
Income from Equity Method Investments	—		15		—		—			15
Interest Income	21		5		9		(6		)	29
Interest Expense	333		76		73		(6		)	476
Income (Loss) before Income Taxes	1,411		431		13		—			1,855
Income Tax Expense (Benefit)	344		66		7		—			417
Net Income (Loss)	$	1,067	$	365	$	6	$	—		$	1,438
Gross Additions to Long-Lived Assets	$	2,896	$	996	$	20	$	—		$	3,912
As of December 31, 2018
Total Assets	$	31,109	$	12,594	$	2,604	$	(981	)	$	45,326
Investments in Equity Method Subsidiaries	$	—	$	86	$	—	$	—		$	86

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	PSE&G		PSEG Power			Other (A)			Eliminations (B)			Consolidated Total
	Millions
Year Ended December 31, 2017
Operating Revenues	$	6,324	$	3,860		$	466		$	(1,556	)	$	9,094
Depreciation and Amortization	685		1,268			33			—			1,986
Operating Income (Loss)	1,760		(367		)	36			—			1,429
Income from Equity Method Investments	—		14			—			—			14
Interest Income	24		3			5			(2		)	30
Interest Expense	303		50			40			(2		)	391
Income (Loss) before Income Taxes	1,536		(250		)	(18		)	—			1,268
Income Tax Expense (Benefit)	563		(729		)	(140		)	—			(306		)
Net Income (Loss)	$	973	$	479		$	122		$	—		$	1,574
Gross Additions to Long-Lived Assets	$	2,919	$	1,231		$	40		$	—		$	4,190
As of December 31, 2017
Total Assets	$	28,554	$	12,418		$	2,666		$	(922	)	$	42,716
Investments in Equity Method Subsidiaries	$	—	$	87		$	—		$	—		$	87


(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.

Note 26. Related-Party Transactions

The following discussion relates to intercompany transactions, which are eliminated during the PSEG consolidation process in accordance with GAAP.

PSE&G

The financial statements for PSE&G include transactions with related parties presented as follows:




	Years Ended December 31,
Related Party Transactions	2019		2018		2017
	Millions
Billings from Affiliates:
Net Billings from PSEG Power (A)	$	1,512	$	1,514	$	1,580
Administrative Billings from Services (B)	310		333		331
Total Billings from Affiliates	$	1,822	$	1,847	$	1,911

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	Years Ended December 31,
Related Party Transactions	2019		2018
	Millions
Receivables from PSEG (C)	$	1	$	123
Payable to PSEG Power (A)	$	307	$	245
Payable to Services (B)	83		76
Accounts Payable—Affiliated Companies	$	390	$	321
Working Capital Advances to Services (D)	$	33	$	33
Long-Term Accrued Taxes Payable	$	115	$	69

PSEG Power

The financial statements for PSEG Power include transactions with related parties presented as follows:




	Years Ended December 31,
Related Party Transactions	2019		2018		2017
	Millions
Billings to Affiliates:
Net Billings to PSE&G (A)	$	1,512	$	1,514	1,580
Billings from Affiliates:
Administrative Billings from Services (B)	$	156	$	145	$	168




	Years Ended December 31,
Related Party Transactions	2019		2018
	Millions
Receivable from PSE&G (A)	$	307	$	245
Receivables from PSEG (C)	101		29
Accounts Receivable—Affiliated Companies	$	408	$	274
Payable to Services (B)	$	5	$	16
Accounts Payable—Affiliated Companies	$	5	$	16
Short-Term Loan to (from) Affiliate (E)	$	149	$	(193	)
Working Capital Advances to Services (D)	$	17	$	17
Long-Term Accrued Taxes Payable	$	115	$	76

(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.

Note 27. Selected Quarterly Data (Unaudited)

The information shown in the following tables, in the opinion of PSEG, PSE&G and PSEG Power includes all adjustments, consisting only of normal recurring accruals, necessary to fairly present such amounts.




	Quarter Ended
	March 31,				June 30, (A)				September 30,				December 31, (B)
	2019		2018		2019		2018		2019		2018		2019		2018
PSEG Consolidated:	Millions, except per share data
Operating Revenues	$	2,980	$	2,818	$	2,316	$	2,016	$	2,302	$	2,394	$	2,478	$	2,468
Operating Income	$	786	$	832	$	160	$	411	$	490	$	554	$	507	$	501
Net Income	$	700	$	558	$	153	$	269	$	403	$	412	$	437	$	199
Earnings Per Share:
Basic:
Net Income	$	1.39	$	1.11	$	0.30	$	0.53	$	0.80	$	0.82	$	0.86	$	0.39
Diluted:
Net Income	$	1.38	$	1.10	$	0.30	$	0.53	$	0.79	$	0.81	$	0.86	$	0.39
Weighted Average Common Shares Outstanding:
Basic	504		504		504		504		504		504		504		504
Diluted	507		507		507		507		507		507		507		508




	Quarter Ended
	March 31,				June 30,				September 30,				December 31,
	2019		2018		2019		2018		2019		2018		2019		2018
PSE&G:	Millions
Operating Revenues	$	2,032	$	1,845	$	1,382	$	1,386	$	1,604	$	1,595	$	1,607	$	1,645
Operating Income	$	465	$	482	$	282	$	358	$	392	$	421	$	330	$	345
Net Income	$	403	$	319	$	227	$	231	$	344	$	278	$	276	$	239




	Quarter Ended
	March 31,				June 30, (A)					September 30,				December 31, (B)
	2019		2018		2019			2018		2019		2018		2019		2018
PSEG Power:	Millions
Operating Revenues	$	1,416	$	1,403	$	1,083		$	767	$	771	$	868	$	1,115	$	1,108
Operating Income (Loss)	$	301	$	329	$	(86	)	$	42	$	79	$	112	$	154	$	113
Net Income (Loss)	$	296	$	234	$	(40	)	$	41	$	53	$	125	$	159	$	(35	)


(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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Note 28. Guarantees of Debt

PSEG Power’s Senior Notes are fully and unconditionally and jointly and severally guaranteed by its subsidiaries, PSEG Fossil LLC, PSEG Nuclear LLC and PSEG Energy Resources & Trade LLC. The following tables present condensed financial information for the guarantor subsidiaries, as well as PSEG Power’s non-guarantor subsidiaries, as of December 31, 2019 and 2018 and for the years ended December 31, 2019, 2018 and 2017.




	PSEG Power			Guarantor Subsidiaries			Other Subsidiaries			Consolidating Adjustments			Total
	Millions
Year Ended December 31, 2019
Operating Revenues	$	—		$	4,315		$	299		$	(229	)	$	4,385
Operating Expenses	12			3,852			302			(229		)	3,937
Operating Income (Loss)	(12		)	463			(3		)	—			448
Equity Earnings (Losses) of Subsidiaries	554			(34		)	14			(520		)	14
Net Gains (Losses) on Trust Investments	3			250			—			—			253
Other Income (Deductions)	168			206			—			(320		)	54
Non-Operating Pension and OPEB Credits (Costs)	—			20			1			—			21
Interest Expense	(284		)	(104		)	(51		)	320			(119		)
Income Tax Benefit (Expense)	39			(265		)	23			—			(203		)
Net Income (Loss)	$	468		$	536		$	(16	)	$	(520	)	$	468
Comprehensive Income (Loss)	$	455		$	565		$	(16	)	$	(549	)	$	455
As of December 31, 2019
Current Assets	$	4,235		$	1,870		$	376		$	(4,755	)	$	1,726
Property, Plant and Equipment, net	46			4,426			3,954			—			8,426
Investment in Subsidiaries	5,363			1,075			—			(6,438		)	—
Noncurrent Assets	300			2,467			100			(214		)	2,653
Total Assets	$	9,944		$	9,838		$	4,430		$	(11,407	)	$	12,805
Current Liabilities	$	1,010		$	2,691		$	2,113		$	(4,755	)	$	1,059
Noncurrent Liabilities	610			2,104			922			(214		)	3,422
Long-Term Debt	2,434			—			—			—			2,434
Member’s Equity	5,890			5,043			1,395			(6,438		)	5,890
Total Liabilities and Member’s Equity	$	9,944		$	9,838		$	4,430		$	(11,407	)	$	12,805
Year Ended December 31, 2019
Net Cash Provided By (Used In) Operating Activities	$	107		$	1,507		$	94		$	(229	)	$	1,479
Net Cash Provided By (Used In) Investing Activities	$	119		$	(846	)	$	(257	)	$	223		$	(761	)
Net Cash Provided By (Used In) Financing Activities	$	(225	)	$	(664	)	$	164		$	6		$	(719	)

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	PSEG Power			Guarantor Subsidiaries			Other Subsidiaries			Consolidating Adjustments			Total
	Millions
Year Ended December 31, 2018
Operating Revenues	$	—		$	4,078		$	224		$	(156	)	$	4,146
Operating Expenses	14			3,460			232			(156		)	3,550
Operating Income (Loss)	(14		)	618			(8		)	—			596
Equity Earnings (Losses) of Subsidiaries	406			(28		)	15			(378		)	15
Net Gains (Losses) on Trust Investments	(1		)	(139		)	—			—			(140		)
Other Income (Deductions)	135			166			—			(280		)	21
Non-Operating Pension and OPEB Credits (Costs)	—			13			2			—			15
Interest Expense	(230		)	(96		)	(30		)	280			(76		)
Income Tax Benefit (Expense)	69			(143		)	8			—			(66		)
Net Income (Loss)	$	365		$	391		$	(13	)	$	(378	)	$	365
Comprehensive Income (Loss)	$	393		$	379		$	(13	)	$	(366	)	$	393
As of December 31, 2018
Current Assets	$	4,317		$	1,479		$	304		$	(4,593	)	$	1,507
Property, Plant and Equipment, net	49			4,971			3,822			—			8,842
Investment in Subsidiaries	5,062			1,107			—			(6,169		)	—
Noncurrent Assets	273			2,109			101			(238		)	2,245
Total Assets	$	9,701		$	9,666		$	4,227		$	(11,000	)	$	12,594
Current Liabilities	$	437		$	2,971		$	2,027		$	(4,593	)	$	842
Noncurrent Liabilities	513			1,996			730			(238		)	3,001
Long-Term Debt	2,791			—			—			—			2,791
Member’s Equity	5,960			4,699			1,470			(6,169		)	5,960
Total Liabilities and Member’s Equity	$	9,701		$	9,666		$	4,227		$	(11,000	)	$	12,594
Year Ended December 31, 2018
Net Cash Provided By (Used In) Operating Activities	$	(74	)	$	1,007		$	42		$	109		$	1,084
Net Cash Provided By (Used In) Investing Activities	$	(402	)	$	(1,034	)	$	(406	)	$	791		$	(1,051	)
Net Cash Provided By (Used In) Financing Activities	$	476		$	27		$	354		$	(900	)	$	(43	)

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	PSEG Power			Guarantor Subsidiaries			Other Subsidiaries			Consolidating Adjustments			Total
	Millions
Year Ended December 31, 2017
Operating Revenues	$	—		$	3,821		$	174		$	(135	)	$	3,860
Operating Expenses	8			4,159			195			(135		)	4,227
Operating Income (Loss)	(8		)	(338		)	(21		)	—			(367		)
Equity Earnings (Losses) of Subsidiaries	567			60			14			(627		)	14
Net Gains (Losses) on Trust Investments	3			122			—			—			125
Other Income (Deductions)	71			91			2			(144		)	20
Non-Operating Pension and OPEB Credits (Costs)	—			8			—			—			8
Interest Expense	(128		)	(49		)	(17		)	144			(50		)
Income Tax Benefit (Expense)	(26		)	588			167			—			729
Net Income (Loss)	$	479		$	482		$	145		$	(627	)	$	479
Comprehensive Income (Loss)	$	518		$	529		$	145		$	(674	)	$	518
Year Ended December 31, 2017
Net Cash Provided By (Used In) Operating Activities	$	(42	)	$	1,185		$	238		$	(55	)	$	1,326
Net Cash Provided By (Used In) Investing Activities	$	506		$	(448	)	$	(525	)	$	(765	)	$	(1,232	)
Net Cash Provided By (Used In) Financing Activities	$	(464	)	$	(736	)	$	307		$	820		$	(73	)

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON

ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

PSEG, PSE&G and PSEG Power

We have established and maintain disclosure controls and procedures as defined under Rule 13a-15(e) and 15d-15(e) promulgated under the Securities Exchange Act of 1934, as amended (the “Exchange Act”) that are designed to provide reasonable assurance that information required to be disclosed in the reports that are filed or submitted under the Exchange Act is recorded, processed, summarized and reported and is accumulated and communicated to the Chief Executive Officer (CEO) and Chief Financial Officer (CFO) of each respective company, as appropriate, by others within the entities to allow timely decisions regarding required disclosure. We have established a disclosure committee which includes several key management employees and which reports directly to the CFO and CEO of each of PSEG, PSE&G and PSEG Power. The committee monitors and evaluates the effectiveness of these disclosure controls and procedures. The CFO and CEO of each of PSEG, PSE&G and PSEG Power have evaluated the effectiveness of the disclosure controls and procedures and, based on this evaluation, have concluded that disclosure controls and procedures at each respective company were effective at a reasonable assurance level as of the end of the period covered by the report.

Internal Controls

PSEG, PSE&G and PSEG Power

We have conducted assessments of our internal control over financial reporting as of December 31, 2019, as required by Section 404 of the Sarbanes-Oxley Act, using the framework promulgated by the Committee of Sponsoring Organizations of the Treadway Commission, commonly referred to as “COSO.” Managements’ reports on PSEG’s, PSE&G’s and PSEG Power’s internal control over financial reporting are included on pages 180, 181 and 182, respectively. The Independent Registered Public Accounting Firm’s report with respect to the effectiveness of PSEG’s internal control over financial reporting is included on page 183. Management has concluded that internal control over financial reporting is effective as of December 31, 2019.

We continually review our disclosure controls and procedures and make changes, as necessary, to ensure the quality of our financial reporting. There have been no changes in internal control over financial reporting that occurred during the fourth quarter of 2019 that have materially affected, or are reasonably likely to materially affect, each registrant’s internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

None.

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MANAGEMENT REPORT ON INTERNAL CONTROL OVER

FINANCIAL REPORTING—PSEG

Management of Public Service Enterprise Group Incorporated (PSEG) is responsible for establishing and maintaining effective internal control over financial reporting and for the assessment of the effectiveness of internal control over financial reporting. As defined by the SEC in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and implemented by the company’s management and other personnel, with oversight by the Audit Committee of the Board of Directors to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America (generally accepted accounting principles).

PSEG’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of PSEG’s assets; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of PSEG are being made only in accordance with authorizations of PSEG’s management and directors; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of PSEG’s assets that could have a material effect on the financial statements.

In connection with the preparation of PSEG’s annual financial statements, management of PSEG has undertaken an assessment, which includes the design and operational effectiveness of PSEG’s internal control over financial reporting based on criteria established in the Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, commonly referred to as “COSO”. The COSO framework is based upon five integrated components of control: control environment, risk assessment, control activities, information and communications and ongoing monitoring.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projection of any evaluation of effectiveness to future periods is subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Based on the assessment performed, management has concluded that PSEG’s internal control over financial reporting is effective and provides reasonable assurance regarding the reliability of PSEG’s financial reporting and the preparation of its financial statements as of December 31, 2019 in accordance with generally accepted accounting principles. Further, management has not identified any material weaknesses in internal control over financial reporting as of December 31, 2019.

PSEG’s external auditors, Deloitte & Touche LLP, have audited PSEG’s financial statements for the year ended December 31, 2019 included in this annual report on Form 10-K and, as part of that audit, have issued a report on the effectiveness of PSEG’s internal control over financial reporting, a copy of which is included in this annual report on Form 10-K.




/s/ RALPH IZZO
Chief Executive Officer

/s/ DANIEL J. CREGG
Chief Financial Officer
February 26, 2020

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MANAGEMENT REPORT ON INTERNAL CONTROL OVER

FINANCIAL REPORTING—PSE&G

Management of Public Service Electric and Gas Company (PSE&G) is responsible for establishing and maintaining effective internal control over financial reporting and for the assessment of the effectiveness of internal control over financial reporting. As defined by the SEC in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and implemented by the company’s management and other personnel, with oversight by the Audit Committee of the Board of Directors of its parent, Public Service Enterprise Group Incorporated, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America (generally accepted accounting principles).

PSE&G’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of PSE&G’s assets; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of PSE&G are being made only in accordance with authorizations of PSE&G’s management and directors; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of PSE&G’s assets that could have a material effect on the financial statements.

In connection with the preparation of PSE&G’s annual financial statements, management of PSE&G has undertaken an assessment, which includes the design and operational effectiveness of PSE&G’s internal control over financial reporting based on criteria established in the Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, commonly referred to as “COSO”. The COSO framework is based upon five integrated components of control: control environment, risk assessment, control activities, information and communications and ongoing monitoring.

Based on the assessment performed, management has concluded that PSE&G’s internal control over financial reporting is effective and provides reasonable assurance regarding the reliability of PSE&G’s financial reporting and the preparation of its financial statements as of December 31, 2019 in accordance with generally accepted accounting principles. Further, management has not identified any material weaknesses in internal control over financial reporting as of December 31, 2019.




/s/ RALPH IZZO
Chief Executive Officer

/s/ DANIEL J. CREGG
Chief Financial Officer
February 26, 2020

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MANAGEMENT REPORT ON INTERNAL CONTROL OVER

FINANCIAL REPORTING—PSEG Power

Management of PSEG Power LLC (PSEG Power) is responsible for establishing and maintaining effective internal control over financial reporting and for the assessment of the effectiveness of internal control over financial reporting. As defined by the SEC in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and implemented by the company’s management and other personnel, with oversight by the Audit Committee of the Board of Directors of its parent, Public Service Enterprise Group Incorporated, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America (generally accepted accounting principles).

PSEG Power’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of PSEG Power’s assets; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of PSEG Power are being made only in accordance with authorizations of PSEG Power’s management and directors; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of PSEG Power’s assets that could have a material effect on the financial statements.

In connection with the preparation of PSEG Power’s annual financial statements, management of PSEG Power has undertaken an assessment, which includes the design and operational effectiveness of PSEG Power’s internal control over financial reporting based on criteria established in the Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, commonly referred to as “COSO”. The COSO framework is based upon five integrated components of control: control environment, risk assessment, control activities, information and communications and ongoing monitoring.

Based on the assessment performed, management has concluded that PSEG Power’s internal control over financial reporting is effective and provides reasonable assurance regarding the reliability of PSEG Power’s financial reporting and the preparation of its financial statements as of December 31, 2019 in accordance with generally accepted accounting principles. Further, management has not identified any material weaknesses in internal control over financial reporting as of December 31, 2019.




/s/ RALPH IZZO
Chief Executive Officer

/s/ DANIEL J. CREGG
Chief Financial Officer
February 26, 2020

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of

Public Service Enterprise Group Incorporated

Opinion on Internal Control over Financial Reporting

We have audited the internal control over financial reporting of Public Service Enterprise Group Incorporated and subsidiaries (the “Company”) as of December 31, 2019, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2019, based on criteria established in Internal Control - Integrated Framework (2013) issued by COSO.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated financial statements and the consolidated financial statement schedule listed in the Index at Item 15(B)(a) as of and for the year ended December 31, 2019 of the Company and our report dated February 26, 2020 expressed an unqualified opinion on those financial statements.

Basis for Opinion

The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management Report on Internal Control Over Financial Reporting - PSEG. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ DELOITTE & TOUCHE LLP

Parsippany, New Jersey

February 26, 2020

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PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE

GOVERNANCE

Executive Officers

PSEG

The information required by Item 10 of Form 10-K with respect to executive officers is set forth in Part I. Information About Our Executive Officers (PSEG).

PSE&G and PSEG Power

Omitted pursuant to conditions set forth in General Instruction I of Form 10-K.

Directors

PSEG

The information required by Item 10 of Form 10-K with respect to (i) present directors of PSEG who are nominees for election as directors at PSEG’s 2020 Annual Meeting of Stockholders, (ii) the director nomination process, and (iii) the composition of the Audit Committee of the Board, is set forth under the headings “Nominees For Director-Biographical Information,” “Overview of Board Nominees-Board Refreshment and Tenure,” and “-Board Membership Selection,” and “Corporate Governance-Board Committees,” respectively, in PSEG’s definitive Proxy Statement for such Annual Meeting of Stockholders, which definitive Proxy Statement is expected to be filed with the U.S. Securities and Exchange Commission (SEC) on or about March 16, 2020 and which information set forth under said heading is incorporated herein by this reference thereto.

PSE&G and PSEG Power

Omitted pursuant to conditions set forth in General Instruction I of Form 10-K.

Standards of Conduct

Our Standards of Conduct (Standards) is a code of ethics applicable to us and our subsidiaries. The Standards are an integral part of our business conduct compliance program and embody our commitment to conduct operations in accordance with the highest legal and ethical standards. The Standards apply to all of our directors and employees (including PSE&G’s, PSEG Power’s, Energy Holdings’ and Services’ respective principal executive officer, principal financial officer, principal accounting officer or Controller and persons performing similar functions). Each such person is responsible for understanding and complying with the Standards. The Standards are posted on our website, http://corporate.pseg.com/aboutpseg/leadershipandgovernance/standardsofconduct. You can get a free copy of the Standards by making an oral or written request directed to:

Vice President, Investor Relations

PSEG Services Corporation

80 Park Plaza, 4th Floor

Newark, NJ 07102

Telephone (973) 430-6565

The Standards establish a set of common expectations for behavior to which each employee must adhere in dealings with investors, customers, fellow employees, competitors, vendors, government officials, the media and all others who may associate their words and actions with us. The Standards have been developed to provide reasonable assurance that, in conducting our business, employees behave ethically and in accordance with the law and do not take advantage of investors, regulators or customers through manipulation, abuse of confidential information or misrepresentation of material facts.

We will post on our website, http://corporate.pseg.com/aboutpseg/leadershipandgovernance/standardsofintegrity:


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


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

In 2019, we did not grant any waivers to the Standards.

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Section 16(a) Beneficial Ownership Reporting Compliance

PSEG

The information required by Item 10 of Form 10-K with respect to compliance with Section 16(a) of the Securities Exchange Act of 1934, as amended, is set forth under the heading “Security Ownership of Directors, Management and Certain Beneficial Owners-Delinquent Section 16(a) Reports” in PSEG’s definitive Proxy Statement for the 2020 Annual Meeting of Stockholders, which definitive Proxy Statement is expected to be filed with the SEC on or about March 16, 2020 and which information set forth under said heading is incorporated herein by this reference thereto.

PSEG Power and PSE&G

Omitted pursuant to conditions set forth in General Instruction I of Form 10-K.

ITEM 11. EXECUTIVE COMPENSATION

PSEG

The information required by Item 11 of Form 10-K is set forth in PSEG’s definitive Proxy Statement for the 2020 Annual Meeting of Stockholders which definitive Proxy Statement is expected to be filed with the SEC on or about March 16, 2020 and such information set forth under such heading is incorporated herein by this reference thereto.

PSEG Power and PSE&G

Omitted pursuant to conditions set forth in General Instruction I of Form 10-K.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND

MANAGEMENT AND RELATED STOCKHOLDER MATTERS

PSEG

The information required by Item 12 of Form 10-K with respect to directors, executive officers and certain beneficial owners is set forth under the heading “Security Ownership of Directors, Management and Certain Beneficial Owners” in PSEG’s definitive Proxy Statement for the 2020 Annual Meeting of Stockholders which definitive Proxy Statement is expected to be filed with the SEC on or about March 16, 2020 and such information set forth under such heading is incorporated herein by this reference thereto.

For information relating to securities authorized for issuance under equity compensation plans, see Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.

PSE&G and PSEG Power

Omitted pursuant to conditions set forth in General Instruction I of Form 10-K.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND

DIRECTOR INDEPENDENCE

PSEG

The information required by Item 13 of Form 10-K is set forth under the heading “Corporate Governance-Certain Relationships and Related Party Transactions” in PSEG’s definitive Proxy Statement for the 2020 Annual Meeting of Stockholders which definitive Proxy Statement is expected to be filed with the SEC on or about March 16, 2020 and such information set forth under such heading is incorporated herein by this reference thereto.

PSEG Power and PSE&G

Omitted pursuant to conditions set forth in General Instruction I of Form 10-K.

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

The information required by Item 14 of Form 10-K is set forth under the heading “Fees Billed by Deloitte for 2019 and 2018” in PSEG’s definitive Proxy Statement for the 2020 Annual Meeting of Stockholders which definitive Proxy Statement is expected to be filed with the SEC on or about March 16, 2020. Such information set forth under such heading is incorporated herein by this reference hereto.

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PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES

(A) The following Financial Statements are filed as a part of this report:


a.	Public Service Enterprise Group Incorporated’s Consolidated Balance Sheets as of December 31, 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.

(B) The following documents are filed as a part of this report:


a.	PSEG’s Financial Statement Schedules:

Schedule II—Valuation and Qualifying Accounts for each of the three years in the period ended December 31, 2019 (page 192).


b.	PSE&G’s Financial Statement Schedules:

Schedule II—Valuation and Qualifying Accounts for each of the three years in the period ended December 31, 2019 (page 192).


c.	PSEG Power’s Financial Statement Schedules:

Schedule II—Valuation and Qualifying Accounts for each of the three years in the period ended December 31, 2019 (page 192).

Schedules other than those listed above are omitted for the reason that they are not required or are not applicable, or the required information is shown in the consolidated financial statements or notes thereto.

LIST OF EXHIBITS:

a.		PSEG:
3a		Certificate of Incorporation Public Service Enterprise Group Incorporated⁽¹⁾
3b		Certificate of Amendment of Certificate of Incorporation of Public Service Enterprise Group Incorporated, effective April 23, 1987⁽²⁾
3c		Certificate of Amendment of Certificate of Incorporation of Public Service Enterprise Group Incorporated, effective April 20, 2007⁽³⁾
3d		By-Laws of Public Service Enterprise Group Incorporated effective December 15, 2015⁽⁴⁾
4a		Indenture between Public Service Enterprise Group Incorporated and First Union National Bank (U.S. Bank National Association, successor), as Trustee, dated January 1, 1998 providing for Deferrable Interest Subordinated Debentures in Series (relating to Quarterly Preferred Securities)⁽⁵⁾
4b		Indenture between Public Service Enterprise Group Incorporated and U.S. Bank National Association (as successor to First Union National Bank), as Trustee, dated November 1, 1998 providing for Senior Debt Securities⁽⁶⁾
4c		Description of Common Stock

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LIST OF EXHIBITS:

10a(1)		Supplemental Executive Retirement Income Plan, amended effective July 1, 2019⁽⁷⁾
10a(2)		Retirement Income Reinstatement Plan for Non-Represented Employees, Amended effective July 1, 2019⁽⁸⁾
10a(3)		2007 Equity Compensation Plan for Outside Directors, amended and restated effective January 1, 2019⁽⁹⁾
10a(4)		Deferred Compensation Plan for Directors, amended effective January 1, 2019⁽¹⁰⁾
10a(5)		Deferred Compensation Plan for Certain Employees, amended and restated effective January 1, 2019⁽¹¹⁾
10a(6)		1989 Long-Term Incentive Plan, as amended⁽¹²⁾
10a(7)		2001 Long-Term Incentive Plan⁽¹³⁾
10a(8)		Senior Management Incentive Compensation Plan⁽¹⁴⁾
10a(9)		Key Executive Severance Plan of Public Service Enterprise Group Incorporated, amended effective July 1, 2019⁽¹⁵⁾
10a(10)		Severance Agreement with Ralph Izzo dated December 16, 2008⁽¹⁶⁾
10a(11)		Stock Plan for Outside Directors, as amended⁽¹⁷⁾
10a(12)		Compensation Plan for Outside Directors⁽¹⁸⁾
10a(13)		2004 Long-Term Incentive Plan, amended and restated as of April 16, 2013⁽¹⁹⁾
10a(14)		Form of Agreement for Advancement of Expenses with Outside Directors⁽²⁰⁾
10a(15)		Equity Deferral Plan, effective January 1, 2019⁽²¹⁾
10a(16)		Agreement with Tamara L. Linde dated June 18, 2014⁽²²⁾
10a(17)		Agreement with Daniel J. Cregg dated September 22, 2015⁽²³⁾
10a(18)		Clawback Practice, effective February 20, 2018⁽²⁴⁾
10a(19)		Agreement with Ralph A. LaRossa dated December 16, 2019
10a(20)		Agreement with David M. Daly dated December 16, 2019
21		Subsidiaries of the Registrant
23		Consent of Independent Registered Public Accounting Firm
31		Certification by Ralph Izzo, pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934 (1934 Act)
31a		Certification by Daniel J. Cregg, pursuant to Rules 13a-14 and 15d-14 of the 1934 Act
32		Certification by Ralph Izzo, pursuant to Section 1350 of Chapter 63 of Title 18 of the U.S. Code
32a		Certification by Daniel J. Cregg, pursuant to Section 1350 of Chapter 63 of Title 18 of the U.S. Code
101.INS		Inline XBRL Instance Document - The instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.
101.SCH		Inline XBRL Taxonomy Extension Schema
101.CAL		Inline XBRL Taxonomy Calculation Linkbase
101.LAB		Inline XBRL Taxonomy Extension Labels Linkbase
101.PRE		Inline XBRL Taxonomy Extension Presentation Linkbase
101.DEF		Inline XBRL Taxonomy Extension Definition Document
104		Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)
b.		PSE&G
3a(1)		Restated Certificate of Incorporation of PSE&G⁽²⁵⁾
3a(2)		Certificate of Amendment of Certificate of Restated Certificate of Incorporation of PSE&G filed February 18, 1987 with the State of New Jersey adopting limitations of liability provisions in accordance with an amendment to New Jersey Business Corporation Act⁽²⁶⁾
3a(3)		Certificate of Amendment of Restated Certificate of Incorporation of PSE&G filed June 17, 1992 with the State of New Jersey, establishing the 7.44% Cumulative Preferred Stock ($100 Par) as a series of Preferred Stock⁽²⁷⁾
3a(4)		Certificate of Amendment of Restated Certificate of Incorporation of PSE&G filed March 11, 1993 with the State of New Jersey, establishing the 5.97% Cumulative Preferred Stock ($100 Par) as a series of Preferred Stock⁽²⁸⁾

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LIST OF EXHIBITS:

3a(5)		Certificate of Amendment of Restated Certificate of Incorporation of PSE&G filed January 27, 1994 with the State of New Jersey, establishing the 6.92% Cumulative Preferred Stock ($100 Par) and the 6.75% Cumulative Preferred Stock ($25 Par) as a series of Preferred Stock⁽²⁹⁾
3b(1)		By-Laws of PSE&G as in effect April 17, 2007⁽³⁰⁾
4a(1)		Indenture between PSE&G and Fidelity Union Trust Company (now, Wachovia Bank, National Association), as Trustee, dated August 1, 1924⁽³¹⁾, securing First and Refunding Mortgage Bond and Supplemental Indentures between PSE&G and U.S. Bank National Association, successor, as Trustee, supplemental to Exhibit 4a(1), dated as follows:
4a(2)		June 1, 1937⁽³²⁾
4a(3)		July 1, 1937⁽³³⁾
4a(4)		June 1, 1991 (No. 1)⁽³⁴⁾
4a(5)		July 1, 1993⁽³⁵⁾
4a(6)		August 1, 2004 (No. 4)⁽³⁶⁾
4a(7)		April 1, 2007⁽³⁷⁾
4a(8)		November 1, 2009⁽³⁸⁾
4a(9)		May 1, 2012⁽³⁹⁾
4a(10)		May 1, 2013⁽⁴⁰⁾
4a(11)		August 1, 2014⁽⁴¹⁾
4a(12)		May 1, 2015⁽⁴²⁾
4a(13)		September 1, 2016⁽⁴³⁾
4a(14)		April 1, 2018⁽⁴⁴⁾
4a(15)		December 1, 2019
4b		Description of the First and Refunding Mortgage Bonds
4c		Indenture of Trust between PSE&G and Chase Manhattan Bank (National Association) (The Bank of New York Mellon, successor), as Trustee, providing for Secured Medium-Term Notes dated July 1, 1993⁽⁴⁵⁾
4d		Indenture dated as of December 1, 2000 between Public Service Electric and Gas Company and First Union National Bank (U.S. Bank National Association, successor), as Trustee, providing for Senior Debt Securities⁽⁴⁶⁾
10a(1)		Supplemental Executive Retirement Income Plan, amended effective July 1, 2019⁽⁷⁾
10a(2)		Retirement Income Reinstatement Plan for Non-Represented Employees, Amended effective July 1, 2019⁽⁸⁾
10a(3)		2007 Equity Compensation Plan for Outside Directors, amended and restated effective January 1, 2019⁽⁹⁾
10a(4)		Deferred Compensation Plan for Directors, amended effective January 1, 2019⁽¹⁰⁾
10a(5)		Deferred Compensation Plan for Certain Employees, amended and restated effective January 1, 2019⁽¹¹⁾
10a(6)		1989 Long-Term Incentive Plan, as amended⁽¹²⁾
10a(7)		2001 Long-Term Incentive Plan⁽¹³⁾
10a(8)		Senior Management Incentive Compensation Plan⁽¹⁴⁾
10a(9)		Key Executive Severance Plan of Public Service Enterprise Group Incorporated, amended effective July 1, 2019⁽¹⁵⁾
10a(10)		Severance Agreement with Ralph Izzo dated December 16, 2008⁽¹⁶⁾
10a(11)		Stock Plan for Outside Directors, as amended⁽¹⁷⁾
10a(12)		Compensation Plan for Outside Directors⁽¹⁸⁾
10a(13)		2004 Long-Term Incentive Plan, amended and restated as of April 16, 2013⁽¹⁹⁾
10a(14)		Form of Agreement for Advancement of Expenses with Outside Directors⁽⁴⁷⁾
10a(15)		Equity Deferral Plan, effective January 1, 2019⁽²¹⁾
10a(16)		Agreement with Tamara L. Linde dated June 18, 2014⁽²²⁾
10a(17)		Agreement with Daniel J. Cregg dated September 22, 2015⁽²³⁾
10a(18)		Clawback Practice, effective February 20, 2018⁽²⁴⁾

188

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LIST OF EXHIBITS:

10a(19)		Agreement with David M. Daly dated December 16, 2019
23a		Consent of Independent Registered Public Accounting Firm
31b		Certification by Ralph Izzo, pursuant to Rules 13a-14 and 15d-14 of the 1934 Act
31c		Certification by Daniel J. Cregg, pursuant to Rules 13a-14 and 15d-14 of the 1934 Act
32b		Certification by Ralph Izzo, pursuant to Section 1350 of Chapter 63 of Title 18 of the U.S. Code
32c		Certification by Daniel J. Cregg, pursuant to Section 1350 of Chapter 63 of Title 18 of the U.S. Code
101.INS		Inline XBRL Instance Document - The instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document
101.SCH		Inline XBRL Taxonomy Extension Schema
101.CAL		Inline XBRL Taxonomy Calculation Linkbase
101.LAB		Inline XBRL Taxonomy Extension Labels Linkbase
101.PRE		Inline XBRL Taxonomy Extension Presentation Linkbase
101.DEF		Inline XBRL Taxonomy Extension Definition Document
104		Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)
c.		PSEG Power:
3a		Certificate of Formation of PSEG Power LLC⁽⁴⁸⁾
3b		PSEG Power LLC Limited Liability Company Agreement⁽⁴⁹⁾
4a		Indenture dated April 16, 2001 between and among PSEG Power, PSEG Fossil, PSEG Nuclear, PSEG Energy Resources & Trade and The Bank of New York Mellon and form of Subsidiary Guaranty included therein⁽⁵⁰⁾
4b		First Supplemental Indenture, dated as of March 13, 2002⁽⁵¹⁾
4c		Description of the Senior Notes
10a(1)		Supplemental Executive Retirement Income Plan, amended effective July 1, 2019⁽⁷⁾
10a(2)		Retirement Income Reinstatement Plan for Non-Represented Employees, Amended effective July 1, 2019⁽⁸⁾
10a(3)		Deferred Compensation Plan for Certain Employees, amended and restated effective January 1, 2019⁽¹¹⁾
10a(4)		1989 Long-Term Incentive Plan, as amended⁽¹²⁾
10a(5)		2001 Long-Term Incentive Plan⁽¹³⁾
10a(6)		Senior Management Incentive Compensation Plan⁽¹⁴⁾
10a(7)		Key Executive Severance Plan of Public Service Enterprise Group Incorporated, amended effective July 1, 2019⁽¹⁵⁾
10a(8)		Severance Agreement with Ralph Izzo dated December 16, 2008⁽¹⁶⁾
10a(9)		2004 Long-Term Incentive Plan, amended and restated as of April 16, 2013⁽¹⁹⁾
10a(10)		Equity Deferral Plan, effective January 1, 2019⁽²¹⁾
10a(11)		Agreement with Tamara L. Linde dated June 18, 2014⁽²²⁾
10a(12)		Agreement with Daniel J. Cregg dated September 22, 2015⁽²³⁾
10a(13)		Clawback Practice, effective February 20, 2018⁽²⁴⁾
10a(14)		Agreement with Ralph A. LaRossa dated December 16, 2019
23b		Consent of Independent Registered Public Accounting Firm
31d		Certification by Ralph Izzo, pursuant to Rules 13a-14 and 15d-14 of the 1934 Act
31e		Certification by Daniel J. Cregg, pursuant to Rules 13a-14 and 15d-14 of the 1934 Act
32d		Certification by Ralph Izzo, pursuant to Section 1350 of Chapter 63 of Title 18 of the U.S. Code
32e		Certification by Daniel J. Cregg, pursuant to Section 1350 of Chapter 63 of Title 18 of the U.S. Code
101.INS		Inline XBRL Instance Document - The instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.
101.SCH		Inline XBRL Taxonomy Extension Schema
101.CAL		Inline XBRL Taxonomy Calculation Linkbase

189

Table of Contents

LIST OF EXHIBITS:

101.LAB		Inline XBRL Taxonomy Extension Labels Linkbase
101.PRE		Inline XBRL Taxonomy Extension Presentation Linkbase
101.DEF		Inline XBRL Taxonomy Extension Definition Document
104		Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)


(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.

190

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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.

191

Table of Contents

Schedule II—Valuation and Qualifying Accounts Years Ended December 31, 2019—December 31, 2017

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED




Column A	Column B		Column C Additions				Column D			Column E
Description	Balance at Beginning of Period		Charged to cost and expenses		Charged to other accounts- describe		Deductions- describe			Balance at End of Period
	Millions
2019
Allowance for Doubtful Accounts	$	63	$	87	$	—	$	90	(A)	$	60
Materials and Supplies Valuation Reserve	9		3		—		1		(B)	11
2018
Allowance for Doubtful Accounts	$	59	$	91	$	—	$	87	(A)	$	63
Materials and Supplies Valuation Reserve	7		4		—		2		(B)	9
2017
Allowance for Doubtful Accounts	$	68	$	76	$	—	$	85	(A)	$	59
Materials and Supplies Valuation Reserve	37		2		—		32		(C)	7


(A)	Accounts Receivable written off.


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


(C)	Hudson and Mercer inventory written off.

PUBLIC SERVICE ELECTRIC AND GAS COMPANY




Column A	Column B		Column C Additions				Column D			Column E
Description	Balance at Beginning of Period		Charged to cost and expenses		Charged to other accounts- describe		Deductions- describe			Balance at End of Period
	Millions
2019
Allowance for Doubtful Accounts	$	63	$	87	$	—	$	90	(A)	$	60
Materials and Supplies Valuation Reserve	2		—		—		—			2
2018
Allowance for Doubtful Accounts	$	59	$	91	$	—	$	87	(A)	$	63
Materials and Supplies Valuation Reserve	—		2		—		—			2
2017
Allowance for Doubtful Accounts	$	68	$	76	$	—	$	85	(A)	$	59
Materials and Supplies Valuation Reserve	—		—		—		—			—


(A)	Accounts Receivable written off.

PSEG POWER LLC




Column A	Column B		Column C Additions				Column D			Column E
Description	Balance at Beginning of Period		Charged to cost and expenses		Charged to other accounts- describe		Deductions- describe			Balance at End of Period
					Millions
2019
Materials and Supplies Valuation Reserve	$	7	$	3	$	—	$	1	(A)	$	9
2018
Materials and Supplies Valuation Reserve	$	7	$	2	$	—	$	2	(A)	$	7
2017
Materials and Supplies Valuation Reserve	$	37	$	2	$	—	$	32	(B)	$	7


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


(B)	Hudson and Mercer inventory written off.

192

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.




			PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

		By:	/s/ RALPH IZZO
			Ralph Izzo
			Chairman of the Board, President and
			Chief Executive Officer

Date: February 26, 2020

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signatures of the undersigned shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.




Signature	Title	Date

/s/ RALPH IZZO	Chairman of the Board, President, Chief Executive Officer and	February 26, 2020
Ralph Izzo	Director (Principal Executive Officer)

/s/ DANIEL J. CREGG	Executive Vice President and Chief Financial Officer	February 26, 2020
Daniel J. Cregg	(Principal Financial Officer)

/s/ ROSE M. CHERNICK	Vice President and Controller	February 26, 2020
Rose M. Chernick	(Principal Accounting Officer)

/s/ WILLIE A. DEESE	Director	February 26, 2020
Willie A. Deese

/s/ WILLIAM V. HICKEY	Director	February 26, 2020
William V. Hickey

/s/ SHIRLEY ANN JACKSON	Director	February 26, 2020
Shirley Ann Jackson

/s/ DAVID LILLEY	Director	February 26, 2020
David Lilley

/s/ BARRY H. OSTROWSKY	Director	February 26, 2020
Barry H. Ostrowsky

/s/ LAURA A. SUGG	Director	February 26, 2020
Laura A. Sugg

/s/ JOHN P. SURMA	Director	February 26, 2020
John P. Surma

/s/ RICHARD J. SWIFT	Director	February 26, 2020
Richard J. Swift

/s/ SUSAN TOMASKY	Director	February 26, 2020
Susan Tomasky

/s/ ALFRED W. ZOLLAR	Director	February 26, 2020
Alfred W. Zollar

193

Table of Contents

SIGNATURES




			PUBLIC SERVICE ELECTRIC AND GAS COMPANY

		By:	/s/ DAVID M. DALY
			David M. Daly
			President

Date: February 26, 2020




Signature	Title	Date

/s/ RALPH IZZO	Chairman of the Board and Chief Executive Officer and	February 26, 2020
Ralph Izzo	Director (Principal Executive Officer)

/s/ DANIEL J. CREGG	Executive Vice President and Chief Financial Officer	February 26, 2020
Daniel J. Cregg	(Principal Financial Officer)

/s/ ROSE M. CHERNICK	Vice President and Controller	February 26, 2020
Rose M. Chernick	(Principal Accounting Officer)

/s/ WILLIAM V. HICKEY	Director	February 26, 2020
William V. Hickey

/s/ SHIRLEY ANN JACKSON	Director	February 26, 2020
Shirley Ann Jackson

/s/ RICHARD J. SWIFT	Director	February 26, 2020
Richard J. Swift

194

Table of Contents

SIGNATURES




			PSEG POWER LLC

		By:	/s/ RALPH A. LAROSSA
			Ralph A. LaRossa
			President

Date: February 26, 2020




Signature	Title	Date

/s/ RALPH IZZO	Chairman of the Board and Chief Executive Officer and	February 26, 2020
Ralph Izzo	Director (Principal Executive Officer)

/s/ DANIEL J. CREGG	Executive Vice President and Chief Financial Officer and	February 26, 2020
Daniel J. Cregg	Director (Principal Financial Officer)

/s/ ROSE M. CHERNICK	Vice President and Controller	February 26, 2020
Rose M. Chernick	(Principal Accounting Officer)

/s/ DEREK M. DIRISIO	Director	February 26, 2020
Derek M. DiRisio

/s/ RALPH A. LAROSSA	Director	February 26, 2020
Ralph A. LaRossa

/s/ TAMARA L. LINDE	Director	February 26, 2020
Tamara L. Linde

/s/ SHEILA ROSTIAC	Director	February 26, 2020
Sheila Rostiac

195


Section 2.03.	Interest on Called Bonds to Cease..................................................................................... 8


Section 2.04.	Bonds Called in Part........................................................................................................... 8


Section 2.05.	Provisions of Indenture Not Applicable............................................................................. 8


Section 3.01.	Credits................................................................................................................................ 8


Section 3.02.	Certificate of the Company................................................................................................ 8


Section 4.03.	Restriction on Dividends.................................................................................................... 9


Section 4.04.	Use of Facsimile Seal and Signatures................................................................................ 9


Section 4.05.	Time for Making of Payment............................................................................................. 9


Section 4.06.	Effective Period of Supplemental Indenture...................................................................... 9


Section 4.07.	Effect of Approval of Board of Public Utilities


Section 4.08.	Execution in Counterparts.................................................................................................. 10



County	Office	Book Number	Page Number
Atlantic	Clerk’s	1955 of Mortgages	160
Bergen	Clerk’s	94 of Chattel Mortgages	123 etc.
Burlington	Clerk’s	693 of Mortgages 52 of Chattel Mortgages	88 etc. Folio 8 etc.
Camden	Register’s	177 of Mortgages 45 of Chattel Mortgages	Folio 354 etc. 184 etc.
Cumberland	Clerk’s	239 of Mortgages 786 of Mortgages	1 etc. 638 & c.
Essex	Register’s	437 of Chattel Mortgages	1-48
		T-51 of Mortgages	341-392
Gloucester	Clerk’s	34 of Chattel Mortgages	123 etc.
Hudson	Register’s	142 of Mortgages 453 of Chattel Mortgages	7 etc. 9 etc.
		1245 of Mortgages	484, etc.
Hunterdon	Clerk’s	151 of Mortgages	344
Mercer	Clerk’s	67 of Chattel Mortgages	1 etc.
Middlesex	Clerk’s	384 of Mortgages 113 of Chattel Mortgages	1 etc. 3 etc.
		437 of Mortgages	294 etc.
Monmouth	Clerk’s	951 of Mortgages	291 & c.
Morris	Clerk’s	N-3 of Chattel Mortgages	446 etc.
		F-10 of Mortgages	269 etc.
Ocean	Clerk’s	1809 of Mortgages	40
Passaic	Register’s	M-6 of Chattel Mortgages	178, etc.
		R-13 of Mortgages	268 etc.
Salem	Clerk’s	267 of Mortgages	249 etc.
Somerset	Clerk’s	46 of Chattel Mortgages	207 etc.
Sussex	Clerk’s	N-10 of Mortgages 123 of Mortgages	1 etc. 10 & c.
Union	Register’s	9584 of Mortgages	259 etc.
Warren	Clerk’s	124 of Mortgages	141 etc.


•	in a principal amount not exceeding the amount of cash deposited by us with the Trustee, to be subsequently withdrawn on account of additions or improvements or as otherwise permitted by the Mortgage, upon compliance with the conditions which, at the time of withdrawal, would authorize the authentication of Bonds in an amount equal to the cash withdrawn, or


•	may be paid to us to reimburse us for the full cost or fair value, whichever be less, of additions or improvements permitted under the Mortgage to be used as the basis for the issuance of additional Mortgage Bonds, without any net earnings requirement;


•	may be paid to us in an amount equal to the principal amount of Mortgage Bonds or certain prior debt bonds purchased, paid, refunded, or retired by us and deposited with the Trustee;


•	may be utilized by the Trustee for the purchase or redemption of Mortgage Bonds at the lowest prices obtainable.


•	default in the payment of the principal of any Mortgage Bonds or prior debt bonds;


•	default, continued for three months, in the payment of interest on any Mortgage Bonds or in the payment of any installment of any sinking fund provided for any series of Mortgage Bonds;


•	default, continued for three months after written notice to us from the Trustee or the holders of 5% in principal amount of the outstanding Mortgage Bonds, in the observance or performance of any other covenant or condition in the Mortgage; and


•	the adjudication of us as a bankrupt, the appointment of a receiver for us or our property or the approval of a petition for our reorganization under the Federal Bankruptcy Code, if no appeal from such action is taken within 30 days, or on the same becoming final.


•	equally in right of payment with our other existing and future senior unsecured indebtedness;


•	senior in right of payment to any of our indebtedness that is expressly subordinated in right of payment to the Senior Notes;


•	effectively junior in right of payment to any of our future secured indebtedness to the extent of the value of the assets securing such indebtedness; and


•	structurally junior to all indebtedness and other liabilities of our subsidiaries that do not guarantee the Senior Notes.


•	equally in right of payment with such guarantor’s other existing and future senior unsecured indebtedness;


•	senior in right of payment to any of such guarantor’s indebtedness that is expressly subordinated in right of payment to the guarantees;


(a)	100% of the principal amount of the Senior Notes being redeemed and


(a)	the average of four reference Treasury Dealer Quotations (as defined below) for the redemption date, after excluding the highest and lowest of those Reference Treasury Dealer Quotations, or


(b)	if the Calculation Agent obtains fewer than four Reference Treasury Dealer Quotations, the average of all Reference Treasury Dealer Quotations obtained.


•	Obligations of ER&T related to the purchase and sale of fuel, capacity, energy (including, but not limited to, electric power, natural gas and coal), environmental credits or entitlements, utility services, fuel, water, related transportation services and other similar or related products and services in the ordinary course of business;