


	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 September 30, 2019
Cash and Cash Equivalents	$	25	$	80	$	15	$	120
Restricted Cash in Other Current Assets	18		—		—		18
Restricted Cash in Other Noncurrent Assets	18		—		—		18
Cash, Cash Equivalents and Restricted Cash	$	61	$	80	$	15	$	156


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

Note 2. Recent Accounting Standards

New ~~Standard~~Standards Issued and Adopted

~~Business Combinations: Clarifying the Definition of a Business~~Leases—Accounting Standards Update (ASU) 2016-02, updated by ASUs 2018-01, 2018-10, 2018-11, 2018-20 and 2019-01

This accounting standard, was issued mainly to provide more consistency in how the definition of a business is applied to acquisitions or dispositions. The new guidance will generally reduce the number of transactions that will require treatment as a business combination. The definition of a business now includes consideration of whether substantially all the fair value of the gross assets acquired or disposed of is concentrated in a single identifiable asset or a group of similar identifiable assets. If this condition is met, the transaction would not qualify as a business.

~~The standard is effective for annual~~ and interim periods beginning after December 15, 2017; however, entities may adopt it for transactions that have closed before the effective date but have not been reported in financial statements that have been issued or made available for issuance. PSEG adopted this standard in the third quarter 2017 with the acquisition of a solar project. This standard upon adoption had no impact on PSEG’s financial statements.

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(UNAUDITED)~~

~~New Standards Issued But Not Yet Adopted~~

~~Revenue from Contracts with Customers~~

This accounting standard clarifies the principles for recognizing revenue and removes inconsistencies in revenue recognition requirements; improves comparability of revenue recognition practices across entities, industries, jurisdictions and capital markets; and provides improved disclosures.

The guidance provides a five-step model to be used for recognizing revenue for the transfer of promised goods and services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods and services.

The standard is effective for annual and interim reporting periods beginning after December 15, 2017. Early application is permitted. PSEG expects the new guidance to result in more detailed disclosures of revenue compared to current guidance and possible changes in presentation. Included in the scope of the new standard are PSE&G’s regulated revenue recorded under tariffs, including the sale of default supply of electric and gas commodity, and the distribution of electricity and gas to retail residential and commercial and industrial customers, and transmission revenues. The tariff revenue comprises substantially all of PSE&G’s revenue. PSEG expects no material change in revenue recognition of PSE&G’s regulated revenue recorded under tariffs. PSE&G’s revenue from contracts with customers will continue to be recorded as electricity or gas is delivered to the customer. PSEG continues to evaluate contracts under its other revenue streams.

Certain implementation issues are currently being finalized by the AICPA’s Financial Reporting Executive Committee, including the ability to recognize revenue for certain contracts where there is uncertainty regarding collection from customers and accounting for contributions in aid of construction. While those issues are out for comment, based on tentative conclusions PSEG does not expect any material changes to its revenue due to those issues. PSEG will adopt this standard on January 1, 2018 and anticipates electing the full retrospective method of transition. Under this method, PSEG will restate its prior period financial statements to align with the 2018 presentation. Certain reclassifications may affect revenue and expense due to the application of this standard; however, PSEG does not anticipate any material impact to net income.

~~Recognition and Measurement of Financial Assets and Financial Liabilities~~

This accounting standard will change how entities measure equity investments that are not consolidated or accounted for under the equity method. Under the new guidance, equity investments (other than those accounted for using the equity method) will be measured at fair value through Net Income instead of Other Comprehensive Income (Loss). Entities that have elected the fair value option for financial liabilities will present changes in fair value due to a change in their own credit risk through Other Comprehensive Income (Loss). For equity investments which do not have readily determinable fair values, the impairment assessment will be simplified by requiring a qualitative assessment to identify impairments. The new standard also changes certain disclosures.

The standard is effective for annual and interim reporting periods beginning after December 15, 2017. PSEG expects to record a cumulative effect adjustment by reclassifying the after-tax net unrealized gain (loss) related to equity investments from Accumulated Other Comprehensive Income to Retained Earnings as of January 1, 2018, and expects increased volatility in Net Income due to changes in fair value of its equity securities within the nuclear decommissioning (NDT) and Rabbi Trust Funds.

~~Leases~~

~~This accounting standard replaces~~updates, replace existing lease accounting guidance and ~~requires~~require lessees to recognize ~~all~~ 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 ~~based on whether control of the underlying assets has transferred to the lessee. A~~and a lessor will classify its leases as operating orleases, direct financing leases, or as sales-type ~~leases based on whether control of the underlying assets has transferred to the lessee. Both the lessee and lessor models require~~leases. The standard requires additional disclosure of key information. The standard requires lessees and lessors to apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. However, existingExisting guidance related to leveraged leases ~~will~~does not change.

PSEG adopted the optional transition method on January 1, 2019. There was no cumulative effect adjustment required to be 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, ~~is effective~~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 ~~annual~~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 ~~interim periods beginning after December 15, 2018~~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 ~~retrospective application to previously issued financial statements for 2018~~this standard. PSE&G’s assets and ~~2017. Early application is permitted.~~liabilities each increased by $91 million and PSEG ~~is currently analyzing the impact~~Power’s assets and liabilities each increased by $46 million. PSEG’s adoption of this standard did not have a material impact on ~~its financial statements.~~the Consolidated Statements of Operations or Consolidated Statements of Cash Flows of PSEG, PSE&G and PSEG Power. See Note 7. Leases for additional information.

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

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

PSEG adopted this standard on January 1, 2019. The ~~amendments expand hedge~~standard requires using a modified retrospective method upon adoption. PSEG analyzed the impact of this standard on its consolidated financial statements and has 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 PSEG’s financial statements.

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

This accounting standard was issued to shorten the amortization period for ~~both non-financial and financial risk components by~~certain callable debt securities held at a premium. Specifically, the standard requires the premium to be amortized to the earliest call date.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

table of ~~January 1, 2018 using a retrospective transition method~~contents

permitting contractually specified components to designate as the hedged risk in a cash flow hedge involving the purchase or sale of non-financial assets or variable rate financial instruments. Additionally, the amendments ease the operational burden of applying hedge accounting by allowing more time to prepare hedge documentation, and allow effectiveness assessments to be performedPSEG adopted this standard on ~~a qualitative basis after hedge inception.~~

~~The new guidance is effective for annual and interim periods beginning after December 15, 2018. The standard requires using~~January 1, 2019 on a modified retrospective ~~method upon adoption. Early adoption is permitted. PSEG is currently analyzing~~basis through a cumulative effect adjustment directly to Retained Earnings as of the ~~impact~~beginning of 2019. Adoption of this standard did not have a material impact on ~~its consolidated~~PSEG’s financial statements.

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.

New Standards Issued But Not Yet Adopted

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

This accounting standard provides a new model for recognizing credit losses on financial ~~assets carried at amortized cost.~~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 ~~should~~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; however, entities may adopt early beginning in~~2019. Adoption of the standard will be applied using a modified retrospective approach through a cumulative-effect adjustment to Retained Earnings as of the effective date of January 1, 2020. PSEG is currently analyzing its financial statements and determining the appropriate methods for calculating credit losses on its various classes of assets, as well as evaluating the overall impact of this standard on its consolidated financial statements.

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 orand interim periods beginning after December 15, ~~2018.~~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. PSEG is currently analyzing the impact of this standard on its financial statements.

~~Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments~~Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract—ASU 2018-15

This accounting standard ~~reduces~~aligns the ~~diversity~~capitalization requirements for implementation costs incurred in ~~practice~~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 ~~how certain cash receipts~~ASC 350—Intangibles—Goodwill and ~~cash payments are~~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 Operation and ~~classified~~Maintenance (O&M) Expense. In addition, the standard also adds presentation requirements for these costs in the ~~Statement~~statements of ~~Cash Flows.~~cash flows and financial position.

The standard is effective for annual and interim periods beginning after December 15, ~~2017; however, entities may adopt early,~~2019. Early adoption is permitted, including adoption in anany interim period. This standard will be applied either retrospectively or prospectively to all implementation costs incurred after the date of adoption. PSEG ~~does not anticipate any current~~is currently analyzing the impact of this standard on ~~PSEG’s~~its financial statements. ~~PSEG will adopt this standard as~~

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Targeted Improvements to ~~each period presented.~~

~~Statement of Cash Flows: Restricted Cash~~Related Party Guidance for Variable Interest Entities (VIE)-ASU 2018-17

This accounting standard ~~requires entities to explain~~improves the ~~change during the period~~VIE guidance in the ~~total~~area of ~~cash, cash equivalents~~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 amounts generally described as restricted cash or restricted cash equivalents, either in a narrative or a tabular format. Amounts generally described as restricted cash or restricted cash equivalents should be included in entities’ reconciliation of beginning-of-period and end-of-period amounts in the Statement of Cash Flows.service providers are variable interests.

~~The~~This standard is effective for annual and interim periods beginning after December 15, ~~2017; however, entities may adopt early, including in an interim period.~~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 ~~plans to adopt~~is currently analyzing the impact of this standard on January 1, 2018 using a retrospective transition method for each period presented. PSEG will continue the current balance sheet classification of restricted cash or restricted cash equivalents. PSEG will provide a reconciliation of cash and cash equivalents and restricted cash or restricted cash equivalents and include a description of these amounts.its financial statements.

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.

~~An entity should apply this~~This standard will be applied on a prospective basis and the entity will be required to disclose 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 ~~is currently assessing the impact~~does not expect adoption of this ~~guidance upon~~standard to have a material impact on its financial statements.

~~Improving~~Disclosure Framework—Changes to the ~~Presentation of Net Periodic Pension Cost and Net Periodic Postretirement~~Disclosure Requirements for Defined Benefit ~~Cost (OPEB)~~Plans—ASU 2018-14

This accounting standard ~~was issued~~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 ~~improve the presentation of net periodic pension cost~~interest crediting rates have been added and ~~net periodic OPEB cost.~~

~~Under the new guidance, entities are required~~certain clarifications were made to ~~report the service cost component in the same line item or items as~~ other ~~compensation costs arising from services rendered by their employees during the period. The other components of net benefit~~

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(UNAUDITED)~~

cost are required to be presented in the Statement of Operations separately from the service cost component after Operating Income. Additionally, only the service cost component will be eligible for capitalization, when applicable.

The standard requires the amendments to be applied retrospectively for the presentation of the service cost component and the other cost components of net periodic pension cost and net periodic OPEB cost in the Statement of Operations and prospectively, on and after the effective date, for the capitalization of the service cost component of net periodic pension and OPEB costs.disclosure requirements.

The standard is effective for ~~annual and interim reporting periods beginning~~fiscal years ending after December 15, ~~2017. Early~~2020 and early adoption is ~~permitted for an entity~~permitted. Amendments in ~~any interim or annual period.~~this standard will be applied on a retrospective basis to all periods presented. PSEG is currently analyzing the impact of this standard on its ~~financial statements.~~disclosures.

~~Premium Amortization on Purchased Callable Debt Securities~~

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. The amendments do not require an accounting change for securities held at a discount; the discount continues to be amortized to maturity.

The standard is effective for annual and interim reporting periods beginning after December 15, 2018. Early adoption is permitted for an entity in any interim or annual period. If an entity early adopts the standard in an interim period, any

adjustments should be reflected as of the beginning of the fiscal year that includes that interim period. An entity should apply this standard on a modified retrospective basis through a cumulative-effect adjustment directly to retained earnings as of the beginning of the period of adoption. Additionally, in the period of adoption, an entity should provide disclosures about a change in accounting principle. PSEG is currently analyzing the impact of this standard on its financial statements.

~~Stock Compensation - Scope of Modification Accounting~~

This accounting standard provides clarity and reduces both diversity in practice and complexity when applying the stock compensation guidance to a change in the terms or conditions of a stock-based payment award. Specifically, the standard provides guidance as to which changes to the terms or conditions of a stock-based payment award require an entity to apply modification accounting.

The standard is effective for all entities for annual periods, and interim periods within those annual periods, beginning after December 15, 2017. Early adoption is permitted, including adoption in any interim period, for reporting periods for which financial statements have not yet been issued. This standard should be applied prospectively to an award modified on or after the adoption date. PSEG plans to adopt this standard effective January 1, 2018.

Note 3. ~~Early Plant Retirements~~Revenues

~~Fossil~~Nature of Goods and Services

~~In October 2016,~~The following is a description of principal activities by reportable segment from which PSEG, PSE&G and PSEG Power ~~determined that it would cease generation operations of~~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 existing coal/gas units at the Hudson and Mercer generating stations on June 1, 2017. Both units were available to operate through May 31, 2017 and were subsequently retired from operation on June 1, 2017.

In the latter half of 2016, PSEG and Power recognized pre-tax charges in Energy Costs and Operation and Maintenance (O&M) of $62 million and $53 million, respectively, related to coal inventory adjustments, capacity penalties, materials and supplies inventory reserve adjustments for parts that cannot be used at other generating units, employee-related severance benefits costs and construction work in progress impairments, among other shut down items. In addition to these charges, Power recognized Depreciation and Amortization (D&A) during 2016 of $571 million dueproduct(s) and/or services are delivered to the ~~significant shortening of~~customer. The electric and gas commodity and delivery tariffs are recurring contracts in effect until modified through the ~~expected economic useful lives of Hudson~~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 ~~Mercer.~~

~~As of June 1, 2017, Power recognized total D&A of $964 million~~gas revenues which represent the estimated amount customers will be billed for services rendered from the ~~Hudson and Mercer units~~most recent meter reading to ~~reflect~~ the end of ~~their economic useful lives in 2017. In~~ the ~~three~~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 ~~nine months ended September 30, 2017, Power~~revenue is recognized ~~pre-tax charges in Energy Costs~~as it is provided to the customer. The formula rate mechanism provides for an annual filing of ~~$1 million~~an estimated revenue requirement with rates effective January 1 of each year and ~~$10 million, respectively,~~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 ~~for coal inventory lower of cost or market adjustments. For the three~~from appliance repair services and nine months ended September 30, 2017, Power also recognized pre-tax charges in O&M of $8 million and $12 million, respectively, of shut down costs and an increase in the Asset Retirement Obligation due to settlements and changes in cash flow estimates, partially offset by changes in employee-related severance costs. Power currently anticipates using the sites for alternative industrial activity. However, if Power determines not to use the sites for alternative industrial activity, the early retirement of the units at such sites would triggersolar generation projects. The performance obligations under ~~certain environmental regulations, including possible remediation. The amounts for any such environmental remediation~~these contracts are ~~neither currently probable nor estimable but may be material.~~satisfied and revenue is recognized as control of products is delivered or services are rendered.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

AsPayment for services rendered and products transferred are typically due within 30 days of ~~December 31, 2016,~~month of delivery.

Revenues Unrelated to Contracts with Customers

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

PSEG Power ~~had reduced~~

Revenues from Contracts with Customers

Electricity and Related Products—Wholesale and retail load contracts are executed in the ~~estimated useful life~~different Independent System Operator (ISO) regions for the bundled supply of ~~Bridgeport Harbor Station unit 3 (BH3) from 2025~~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 ~~summer~~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 Condensed Consolidated Statements of ~~2021 as it was more likely than not it will retire~~Operations. The classification depends on the ~~unit by this time.~~net hourly activity.

PSEG Power enters into capacity sales and ~~Power continue to monitor their other coal assets, including the Keystone and Conemaugh generating stations, to assess their economic viability~~capacity purchases through the ~~end~~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 ~~their designated useful lives~~the capacity and ~~their continued classification as held~~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 ~~use. The precise timing of a change~~approximately three years, through May 2022 from the electric distribution companies (EDCs) in ~~useful lives may be dependent upon events out of PSEG’s and Power’s control and may impact their ability to operate or maintain certain assets~~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 ~~future. These generating stations may be impacted~~tables below. 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 ~~factors such~~either party with a two-year notice. The performance obligation is primarily delivery of gas which is satisfied over time. Revenue is recognized as ~~environmental legislation, co-owner capital requirements~~gas is delivered. Based upon the availability of natural gas, storage and ~~continued depressed wholesale power prices~~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, ~~factors, among other things. Any early retirement or change~~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 13. 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, Long Island Electric Utility Servco, LLC (Servco) records costs which are recovered from LIPA and records the recovery of those costs as revenues when Servco is a principal in the ~~held for use classification of our remaining coal units may have a material adverse impact on PSEG’s and Power’s future financial results.~~

~~Nuclear~~

Since 2013, several nuclear generating stations in the United States have closed or announced early retirement due to economic reasons, or have announced being at risk for early retirement. This situation is generally due to thedecline in market prices of energy, resulting from low natural gas prices driven by the growth of shale gas production since 2007, the continuing cost of regulatory compliance and enhanced security for nuclear facilities and both federal and state-level policies that provide financial incentives to renewable energy such as wind and solar, but generally do not apply to nuclear generating stations. These trends have significantly reduced the revenues of nuclear generating stations while limiting their ability to reduce the unit cost of production. This may result in the electric generation industry experiencing a shift from nuclear generation to natural gas-fired generation, creating less diversity of the generation fleet.

If the market trends noted above continue or worsen, Power’s New Jersey nuclear generating units could cease being economically competitive which may cause Power to retire such units prior to the end of their useful lives. The costs associated with any such potential retirement, which may include, among other things, accelerated D&A or impairment charges, accelerated asset retirement costs, severance costs, environmental remediation costs, and additional funding of the NDT Fund would likely have a material adverse impact on PSEG’s and Power’s future financial results and cash flows. PSEG and Power continue to advocate for sound policies that recognize nuclear power as a source of reliable clean energy, free of air emissions and an important part of a diverse and reliable energy portfolio.

The following table provides the balance sheet amounts by generating station as of September 30, 2017 for significant assets and liabilities associated with Power’s owned share of its nuclear assets.

As of September 30, 2017
Hope Creek Salem Support Facilities and Other (A) Peach Bottom
Millions
Assets
Materials and Supplies Inventory $ 85
$ 81
$ —
$ 41

Nuclear Production, net of Accumulated Depreciation 452
557
204
753

Nuclear Fuel In-Service, net of Accumulated Depreciation 120
94
—
109

Construction Work in Progress (including nuclear fuel) 216
130
9
92

        Total Assets $ 873
$ 862
$ 213
$ 995

Liability
Asset Retirement Obligation $ 148
$ 162
$ —
$ 164

        Total Liabilities $ 148
$ 162
$ —
$ 164

         Net Assets $ 725
$ 700
$ 213
$ 831

NRC License Renewal Term 2046 2036/2040
—
2033/2034

% Owned 100 % 57 % —
50 %


~~(A)~~	~~Includes Hope Creek’s and Salem’s shared support facilities and other nuclear development capital.~~

The precise timing of any potential early retirement and resulting financial statement impact may be affected by a number of factors, including co-owner considerations, the results of any transmission system reliability study assessments andtransaction.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

~~decommissioning trust fund requirements~~Revenues Unrelated to Contracts with Customers

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

Disaggregation of Revenues




	PSE&G		PSEG Power			Other		Eliminations			Consolidated
	Millions
Three Months Ended September 30, 2019
Revenues from Contracts with Customers
Electric Distribution	$	1,096	$	—		$	—	$	—		$	1,096
Gas Distribution	130		—			—		(5		)	125
Transmission	295		—			—		—			295
Electricity and Related Product Sales
PJM
Third Party Sales	—		488			—		—			488
Sales to Affiliates	—		160			—		(160		)	—
New York ISO	—		38			—		—			38
ISO New England	—		37			—		—			37
Gas Sales
Third Party Sales	—		12			—		—			12
Sales to Affiliates	—		58			—		(58		)	—
Other Revenues from Contracts with Customers (A)	64		13			141		(1		)	217
Total Revenues from Contracts with Customers	1,585		806			141		(224		)	2,308
Revenues Unrelated to Contracts with Customers (B)	19		(35		)	10		—			(6		)
Total Operating Revenues	$	1,604	$	771		$	151	$	(224	)	$	2,302




	PSE&G		PSEG Power		Other			Eliminations			Consolidated
	Millions
Nine Months Ended September 30, 2019
Revenues from Contracts with Customers
Electric Distribution	$	2,613	$	—	$	—		$	—		$	2,613
Gas Distribution	1,272		—		—			(11		)	1,261
Transmission	887		—		—			—			887
Electricity and Related Product Sales
PJM
Third Party Sales	—		1,426		—			—			1,426
Sales to Affiliates	—		416		—			(416		)	—
New York ISO	—		108		—			—			108
ISO New England	—		85		—			—			85
Gas Sales
Third Party Sales	—		70		—			—			70
Sales to Affiliates	—		639		—			(639		)	—
Other Revenues from Contracts with Customers (A)	196		37		406			(3		)	636
Total Revenues from Contracts with Customers	4,968		2,781		406			(1,069		)	7,086
Revenues Unrelated to Contracts with Customers (B)	50		489		(27		)	—			512
Total Operating Revenues	$	5,018	$	3,270	$	379		$	(1,069	)	$	7,598

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)




	PSE&G		PSEG Power			Other		Eliminations			Consolidated
	Millions
Three Months Ended September 30, 2018
Revenues from Contracts with Customers
Electric Distribution	$	1,072	$	—		$	—	$	—		$	1,072
Gas Distribution	142		—			—		(6		)	136
Transmission	312		—			—		—			312
Electricity and Related Product Sales
PJM
Third Party Sales	—		558			—		—			558
Sales to Affiliates	—		166			—		(166		)	—
New York ISO	—		56			—		—			56
ISO New England	—		12			—		—			12
Gas Sales
Third Party Sales	—		24			—		—			24
Sales to Affiliates	—		47			—		(47		)	—
Other Revenues from Contracts with Customers (A)	60		12			142		(1		)	213
Total Revenues from Contracts with Customers	1,586		875			142		(220		)	2,383
Revenues Unrelated to Contracts with Customers (B)	9		(7		)	9		—			11
Total Operating Revenues	$	1,595	$	868		$	151	$	(220	)	$	2,394




	PSE&G		PSEG Power		Other		Eliminations			Consolidated
	Millions
Nine Months Ended September 30, 2018
Revenues from Contracts with Customers
Electric Distribution	$	2,516	$	—	$	—	$	—		$	2,516
Gas Distribution	1,149		—		—		(13		)	1,136
Transmission	925		—		—		—			925
Electricity and Related Product Sales
PJM
Third Party Sales	—		1,429		—		—			1,429
Sales to Affiliates	—		489		—		(489		)	—
New York ISO	—		161		—		—			161
ISO New England	—		73		—		—			73
Gas Sales
Third Party Sales	—		118		—		—			118
Sales to Affiliates	—		552		—		(552		)	—
Other Revenues from Contracts with Customers (A)	195		35		404		(3		)	631
Total Revenues from Contracts with Customers	4,785		2,857		404		(1,057		)	6,989
Revenues Unrelated to Contracts with Customers (B)	41		181		17		—			239
Total Operating Revenues	$	4,826	$	3,038	$	421	$	(1,057	)	$	7,228


(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.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)


(B)	Includes primarily alternative revenues at PSE&G, derivative contracts at PSEG Power, and lease contracts in Other. For the nine months ended September 30, 2019, Other includes a $58 million pre-tax charge related to one of Energy Holdings’ lease investments. See Note 8. Financing Receivables for additional information.

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 September 30, 2019 and December 31, 2018. Substantially all of PSE&G’s accounts receivable result from contracts with customers that are priced at tariff rates. Allowances represented approximately 7 percent of accounts receivable as of September 30, 2019 and December 31, 2018.

PSEG Power

PSEG Power generally collects consideration upon satisfaction of performance obligations, and therefore, PSEG Power had no material contract balances as of September 30, 2019 and December 31, 2018.

PSEG Power’s accounts receivable include amounts resulting from contracts with customers and other ~~commitments,~~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 Condensed 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 did not have any material contract balances as ~~well~~of September 30, 2019 and December 31, 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 ~~energy prices.~~performance obligations under contracts with fixed consideration as follows:

PSEG Power ~~maintains~~

As stated above, capacity transactions with ISOs are reported on a ~~NDT Fund~~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 ~~funds its decommissioning obligations. See~~were sold in September 2019. For additional information see Note ~~7. Available-for-Sale Securities.~~4. Early Plant Retirements/Asset Dispositions.




Delivery Year	$ per 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 New England ISO 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 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:

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)




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 2019 is $65 million and could increase each year based on the change in the Consumer Price Index (CPI). The incentive for 2019 can range from zero to approximately $10 million and could increase each year thereafter based on the change in the CPI.

Note 4. Early Plant Retirements/Asset Dispositions

Nuclear

In April 2019, PSEG Power’s Salem 1, Salem 2 and Hope Creek nuclear plants were awarded Zero Emission Certificates (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 (which is equivalent to approximately $10 per megawatt hour (MWh) 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, subject to exceptions specified in the ZEC legislation. PSEG Power anticipates it will 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. The financial condition of the plants may nonetheless be materially adversely impacted by potential changes to the capacity market construct being considered by FERC (absent sufficient capacity revenues provided under a program approved by the BPU in accordance with a FERC- authorized capacity mechanism), and, 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. Absent a material financial change, these adverse impacts could still result in PSEG Power taking all necessary steps to retire all of these plants following the end of the initial three year term of the ZECs program. 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.

Note 5. Variable Interest Entity (VIE)

VIE for which PSEG LI is the Primary Beneficiary

PSEG LI consolidates ~~Long Island Electric Utility~~ Servco, ~~LLC (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

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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. Servco recorded ~~$114~~$124 million and ~~$116~~$126 million for the three months and ~~$338~~$357 million and ~~$315~~$355 million for the nine months ended September 30, ~~2017~~2019 and ~~2016,~~2018, 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 Condensed Consolidated Statement of Operations.

Note 5.6. Rate Filings

This Note should be read in conjunction with Note 6.7. Regulatory Assets and Liabilities to the Consolidated Financial Statements in the Annual Report on Form 10-K for the year ended December 31, ~~2016.~~2018.

In addition to items previously reported in the Annual Report on Form 10-K, significant regulatory orders received and currently pending rate filings with FERC and the BPU by PSE&G are as follows:

Transmission Formula Rate Filings—In ~~June 2017,~~October 2019, PSE&G filed its ~~2016~~2019 Annual Transmission Formula Rate 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 ~~2016.~~2018. This filing resulted in an additional revenue requirement adjustment of ~~$12~~$52 million more than the ~~2016~~2018 originally filed ~~revenues.~~revenue requirement. PSE&G had previously recognized the majority of the additional revenue requirement in its 2018 Consolidated Statement of Operations.

Tax Adjustment Credit (TAC)—In September 2019, PSE&G made its initial annual TAC filing following the implementation of the TAC as 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 tax rates provided in the Tax Cuts and Jobs Act of 2017 (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 2019 TAC filing requests BPU approval to reduce electric and gas revenues by approximately $15 million and $10 million, respectively, on an annual basis starting January 1, 2020.

BGSS—In September 2019, the BPU provisionally approved PSE&G’s request to decrease its BGSS rates which will decrease annual BGSS revenues by approximately $13 million. The BGSS rate decreased from approximately 35 cents to 34 cents per therm for residential gas customers effective October 1, 2019.

In March 2019, the BPU approved the final BGSS rates which were effective October ~~2017, the 2018 Annual Formula Rate update was filed with FERC and requests approximately $212 million in increased annual transmission revenue effective January~~ 1, ~~2018, subject to true-up.~~2018.

Gas System Modernization Program ~~(GSMP)~~I (GSMP I)—In ~~July of each year, PSE&G files with~~September 2019, the BPU ~~for base rate recovery of~~approved PSE&G’s final GSMP ~~investments which include a return of and on its investment.~~

~~In October 2017, PSE&G submitted the planned update to its annual GSMP~~I cost recovery petition ~~originally filed~~requesting approximately $11 million in ~~July 2017, to include~~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.

Gas System Modernization Program II (GSMP II)—In September ~~30, 2017. This filing~~2019, PSE&G updated its first GSMP II cost recovery petition to include GSMP II investments in service as of August 31, 2019. The updated petition seeks BPU approval to recover in gas base rates an estimated annual revenue increase of ~~$25~~$17 million effective ~~January~~December 1, ~~2018. This increase represents the return of and on investment for GSMP investments in service through September 30, 2017. This proceeding is ongoing.~~ 2019.

~~Energy Strong~~Green Program Recovery ~~Filing~~Charges (GPRC)—In ~~March and~~ September ~~of each year, PSE&G files with the BPU for base rate recovery of Energy Strong investments which include a return of and on its investment.~~

In June 2017, PSE&G submitted the planned update to its March Energy Strong cost recovery petition, originally filed in March 2017, to include Energy Strong investments in service as of May 31, 2017. This filing requested estimated annual increases in electric and gas revenues of $16 million and $2 million, respectively. In August 2017,2019, the BPU approved ~~these rate increases effective September 1, 2017.~~

~~In September~~a one year extension of PSE&G’s Energy Efficiency (EE) 2017 ~~PSE&G filed~~component of its ~~Energy Strong electric cost~~GPRC programs, authorizing an additional $27 million of EE Investments and $6 million of additional administrative costs for recovery petition seeking BPU approval to recover the revenue requirements associated with Energy Strong capitalized investment costs placed in service from June 1, 2017 through November 30, 2017. The petition requests rates to be effective March 1, 2018, consistent with the BPU Order of approval of thethough its existing filing mechanism.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

~~Energy Strong program. The annualized requested increase~~In June 2019, PSE&G filed its 2019 GPRC cost recovery petition requesting recovery of approximately $52 million and $11 million in electric ~~revenue requirement is approximately $9 million. This proceeding is ongoing.~~

~~Basic Gas Supply Services (BGSS)~~—In June 2017, PSE&G made its annual BGSS filing with the BPU requesting an increase in the BGSS rate from approximately 34 cents to 37 cents per therm effective October 1, 2017. In September 2017, the BPU approved a Stipulation in this matter on a provisional basis and ~~the BGSS rate was increased.~~

~~Weather Normalization Clause—In April 2017, the BPU gave final approval to PSE&G’s petition to collect $54 million in net deficiency~~ gas revenues, ~~as a result of the warmer than normal 2015-2016 Winter Period.~~respectively, on an annual basis. This matter is pending.

In June 2017, PSE&G filed a petition requesting approval to collect $55 million in total net deficiency revenues comprised of $31 million in net deficiency gas revenues as a result of the warmer than normal 2016-2017 Winter Period and the remaining carryover balance of $24 million in net deficiency gas revenue from the 2015-2016 Winter Period. The deficiency gas revenue would be collected from customers over the 2017-2018 and 2018-2019 Winter Periods (October 1 through May ~~31). In September 2017, the BPU approved this petition on a provisional basis with rates effective October 1, 2017, allowing recovery during the 2017-2018 Winter Period.~~

~~Green Program Recovery Charges (GPRC)—In August 2017,~~2019, the BPU approved PSE&G’s petition for an Energy Efficiency 2017 Program (EE 2017) to extend three existing energy efficiency subprograms (multi-family, direct install and hospital efficiency) and establish two new residential energy efficiency offerings. The two new offerings include deployment of smart thermostats and a pilot program to provide residential customers with energy usage information enabling them to reduce consumption. The Order allows PSE&G to extend the subprogram offerings and establish the residential energy efficiency sub-programs under its existing energy efficiency clause recovery process. The EE 2017 allows for $69 million of additional investment and $16 million of additional administrative and information technology costs. The EE 2017 was added as the 11th component of the GPRC rate effective September 1, 2017.

Each year PSE&G files with the BPU for annual recovery for the 11 combined components of its electric and gas Green Program investments which include a return on its investment and recovery of expenses.

~~In March 2017, the BPU gave final approval to PSE&G’s 2016~~2018 GPRC cost recovery petition ~~to recover~~requesting recovery of approximately ~~$37~~$65 million and ~~$13~~$6 million in electric and gas revenues, respectively, on an annual ~~basis associated with~~basis.

Weather Normalization Clause (WNC)—In September 2019, the BPU approved PSE&G’s ~~implementation~~2019-2020 WNC rates on a provisional basis allowing an approximate $8 million of these BPU approved GPRC programs for the period October 1, 2016 through September 30, 2017. The rates were effective May 1, 2017. This Order also included the return of approximately $5 million in remaining overcollections from the ~~completed Securitization Transition Charge.~~ 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 June 2017, PSE&G filed its 2017 GPRC cost recovery petition requesting recovery of approximately $47 million and $13 million in electric and gas revenues, respectively, on an annual basis associated with PSE&G's implementation of these BPU-approved programs for the period October 1, 2017 through September 30, 2018. This proceeding is ongoing.

~~Remediation Adjustment Charge (RAC)—In June 2017,~~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.

Remediation Adjustment Clause (RAC)—In August 2019, the BPU approved PSE~~&G's~~&G’s filing with respect to its RAC 2426 petition allowing recovery of ~~$41~~$73 million effective ~~July 10, 2017~~September 1, 2019 related to ~~net~~ Manufactured Gas Plant (MGP) remediation expenditures from August 1, ~~2015~~2017 through July 31, ~~2016.~~2018.

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 kilowatt-hour 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 7. Leases

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.

As of September 30, 2019, PSEG and subsidiaries were both a lessee and a lessor in Operating Leases. PSEG and subsidiaries were neither the lessee nor the lessor in any material non-operating leases.

Lessee

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 Condensed Consolidated Balance Sheets of PSEG, PSE&G and PSEG Power. PSEG and its subsidiaries have elected an accounting policy to exclude the application of ASC 842 requirements to recognize Operating Lease Right-of-Use Assets and Operating Lease Liabilities for leases where the term is twelve months or less.

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.

PSEG and its subsidiaries recognize the lease payments in O&M Expense 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 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.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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.

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 2052, some of which include options to extend the leases for up to 7 5-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.

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 2 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 8 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 Condensed Consolidated Statements of Operations during the three and nine months ended September 30, 2019 and any amounts capitalized as part of the cost of another asset, and the cash flows arising from lease transactions.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)




	PSE&G			PSEG Power			Other			Total
	Millions
Operating Lease Costs
Three Months Ended September 30, 2019
Long-term Lease Costs	$	7		$	4		$	3		$	14
Short-term Lease Costs	3			2			—			5
Variable Lease Costs	—			5			2			7
Total Operating Lease Costs	$	10		$	11		$	5		$	26
Nine Months Ended September 30, 2019
Long-term Lease Costs	$	16		$	9		$	11		$	36
Short-term Lease Costs	12			7			—			19
Variable Lease Costs	1			7			7			15
Total Operating Lease Costs	$	29		$	23		$	18		$	70

Three Months Ended September 30, 2019
Cash Paid for Amounts Included in the Measurement of Operating Lease Liabilities	$	5		$	4		$	3		$	12
Nine Months Ended September 30, 2019
Cash Paid for Amounts Included in the Measurement of Operating Lease Liabilities	$	12		$	8		$	11		$	31

Weighted Average Remaining Lease Term in Years	13			13			11			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

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Operating Lease Liabilities as of September 30, 2019 had the following maturities:




	PSE&G		PSEG Power		Other		Total
	Millions
2019	$	4	$	3	$	4	$	11
2020	15		13		16		44
2021	12		13		16		41
2022	10		14		15		39
2023	8		8		15		31
2024	8		3		15		26
Thereafter	67		48		90		205
Total Minimum Lease Payments	$	124	$	102	$	171	$	397

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




	As of September 30, 2019
	PSE&G			PSEG Power			Other			Total
	Millions
Undiscounted Cash Flows	$	124		$	102		$	171		$	397
Reconciling Amount due to Discount Rate	(27		)	(29		)	(33		)	(89		)
Total Discounted Operating Lease Liabilities	$	97		$	73		$	138		$	308

As of September 30, 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

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, as lessors, 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. Energy Holdings’ leveraged leases are accounted for in Operating Revenues and in Noncurrent Long-Term Investments. See Note 8. Financing Receivables.

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 September 30, 2019, PSEG Power’s solar generating plants subject to these leases had a total carrying value of $333 million.

Other

Energy Holdings is the lessor in leveraged leases. Leveraged lease accounting guidance is grandfathered for existing leveraged leases. If modified after January 1, 2019, those leveraged leases will be accounted for as operating or financing leases. See Note 8. Financing Receivables.

Energy Holdings is the lessor in various Operating Leases for real estate with remaining terms through 2033. As of September 30, 2019, Energy Holdings’ property subject to these leases had a total carrying value of $24 million.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

The following is the Operating Lease Income for PSEG Power and Energy Holdings for the three and nine months ended September 30, 2019:




	PSEG Power		Energy Holdings		Total
	Millions
Operating Lease Income
Three Months Ended September 30, 2019
Fixed Lease Income	$	—	$	6	$	6
Variable Lease Income	7		—		7
Total Operating Lease Income	$	7	$	6	$	13
Nine Months Ended September 30, 2019
Fixed Lease Income	$	—	$	17	$	17
Variable Lease Income	19		—		19
Total Operating Lease Income	$	19	$	17	$	36

Energy Holdings’ Operating Leases had the following minimum future fixed lease receipts as of September 30, 2019:




	Millions
2019	$	2
2020	20
2021	18
2022	17
2023	17
2024	16
Thereafter	171
Total Minimum Future Lease Receipts	$	261

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Note 6.8. 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 Condensed Consolidated Balance Sheets. The following table reflects the outstanding loans by class of customer, none of which ~~are~~would be considered “non-performing.”

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~




Outstanding Loans by Class of Customer
	As of			As of
Consumer Loans	September 30, 2019			December 31, 2018
	Millions
Commercial/Industrial	$	153		$	164
Residential	8			9
Total	$	161		$	173
Current Portion (included in Accounts Receivable)	(24		)	(24		)
Noncurrent Portion (included in Long-Term Investments)	$	137		$	149

~~(UNAUDITED)~~

Outstanding Loans by Class of Customer
As of As of
Consumer Loans September 30,
2017 December 31,
2016
Millions
Commercial/Industrial $ 160
$ 164

Residential 10
11

Total $ 170
$ 175

Energy Holdings

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 Condensed 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 Condensed 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 Condensed Consolidated Balance Sheets.

During the ~~third~~second quarter of ~~2016,~~2019, Energy Holdings completed its annual review of estimated residual values embedded in the

~~NRG REMA, LLC (REMA)~~ leveraged leases. The outcome indicated that the ~~revised~~updated residual value ~~estimates were~~estimate of the coal-fired Powerton lease was lower than the recorded residual ~~values~~value and the decline was deemed to be other than temporary ~~due to the~~as a result of expected future adverse ~~economic conditions experienced by coal generation in PJM, as discussed in Note 3. Early Plant Retirements, negatively impacting the economic outlook of the leased assets.~~market conditions. As a result, a pre-tax write-down of ~~$137~~$58 million was reflected in Operating Revenues in the quarter ended ~~September~~June 30, ~~2016,~~2019, calculated by comparing the gross investment in the leases before and after the revised residual estimates. During the fourth quarter of 2016, Energy Holdings recorded a $10 million pre-tax charge for its best estimate of loss related to the leveraged lease receivables as a result of the current liquidity issues facing REMA, which was reflected in Operating Revenues and is included in Gross Investments in Leases as of December 31, 2016.

During the first quarter of 2017, due to continuing liquidity issues facing REMA, economic challenges facing coal generation in PJM, and based upon an ongoing review of available alternatives as well as certain recent discussions with REMA management, Energy Holdings recorded an additional $55 million pre-tax charge for its current best estimate of loss related to the lease receivables, which was reflected in Operating Revenues and is included in Gross Investments in Leases as of September 30, 2017.

In June 2017, GenOn Energy, Inc. (GenOn) and certain of its subsidiaries filed voluntary petitions for relief under Chapter 11 of the United States Bankruptcy Code. GenOn is a subsidiary of NRG Energy, Inc. and is the parent of REMA. REMA was not included in the GenOn filing. Energy Holdings continues to monitor the restructuring of GenOn and its possible impacts on REMA and continues to discuss the situation with GenOn. During the second quarter of 2017, Energy Holdings completed its review of estimated residual values embedded in its leveraged lease portfolio of generating assets and the outcome indicated that one of the residual value estimates was lower than the recorded residual value due to a further deterioration of market conditions and changes to operating cost estimates. This decline was determined to be other than temporary. As a result, a pre-tax write-down of $7 million was recorded in the quarter ended June 30, 2017. In addition, based on an ongoing review of (i) the liquidity challenges facing REMA and (ii) available alternatives, Energy Holdings recorded an additional $15 million pre-tax charge for its current best estimate of loss related to lease receivables. The second quarter 2017 pre-tax write-down and additional charge were reflected in Operating Revenues and are included in Gross Investment in Leases for September 30, 2017.

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(UNAUDITED)~~

The following table shows Energy Holdings’ gross and net lease investment as of September 30, ~~2017~~2019 and December 31, ~~2016, respectively.~~2018.




	As of			As of
	September 30, 2019			December 31, 2018
	Millions
Lease Receivables (net of Non-Recourse Debt)	$	500		$	504
Estimated Residual Value of Leased Assets	201			326
Total Investment in Rental Receivables	701			830
Unearned and Deferred Income	(208		)	(290		)
Gross Investments in Leases	493			540
Deferred Tax Liabilities	(331		)	(354		)
Net Investments in Leases	$	162		$	186

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

As of As of
September 30,
2017 December 31,
2016
Millions
Lease Receivables (net of Non-Recourse Debt) $ 546
$ 629

Estimated Residual Value of Leased Assets 326
346

Total Investment in Rental Receivables 872
975

Unearned and Deferred Income (309 ) (326 )
Gross Investment in Leases 563
649

Deferred Tax Liabilities (631 ) (674 )
Net Investment in Leases $ (68 ) $ (25 )

The corresponding receivables associated with the lease portfolio are reflected ~~in the following table,~~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 and Poor’s (S&P) as of September 30, 2019
	As of September 30, 2019
	Millions
AA	$	12
A-	58
BBB+ — BBB-	258
BB	133
NR	39
Total	$	500

Lease Receivables, Net of
Non-Recourse Debt

Counterparties’ Credit Rating Standard & Poor’s (S&P) as of September 30, 2017
As of September 30, 2017
Millions
AA $ 15

BBB+ — BBB- 316

BB- 133

CCC- 82

Total $ 546

The ~~“BB-”~~“BB” and the ~~“CCC-”~~“NR” ratings in the preceding table represent lease receivables related to coal and gas-fired assets in Illinois and Pennsylvania, respectively. As of September 30, ~~2017~~2019, the gross investment in the leases of such assets, net of non-recourse debt, was $~~337~~236 million ($~~(184)~~(25) million, net of deferred taxes). A more detailed description of such assets under lease ~~as of September 30, 2017,~~ is presented in the following table.

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

Asset Location
Gross
Investment

%
Owned
Total MW
Fuel
Type

Counterparties’
S&P Credit
Ratings
Counterparty
Millions
Powerton Station Units 5 and 6 IL $ 133
64 % 1,538
Coal BB- NRG Energy, Inc.
Joliet Station Units 7 and 8 IL $ 84
64 % 1,036
Gas BB- NRG Energy, Inc.
Keystone Station Units 1 and 2 PA $ 20
17 % 1,711
Coal CCC- REMA (A)
Conemaugh Station Units 1 and 2 PA $ 20
17 % 1,711
Coal CCC- REMA (A)
Shawville Station Units 1, 2, 3 and 4 PA $ 80
100 % 596
Gas CCC- REMA (A)


~~(A)~~	REMA’s parent company, GenOn, and certain of its subsidiaries (which did not include REMA) filed voluntary petitions for relief under Chapter 11 of the U.S. Bankruptcy Code. GenOn is currently engaged in a balance sheet restructuring, which will take an undetermined time to complete.

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(UNAUDITED)~~

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 and may include letters of credit or affiliate guarantees.~~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. Failure to recover adequate value could ultimately lead to a foreclosure on the assets under lease by the lenders. Although all lease payments are current, PSEG cannot predict the outcome of GenOn’s restructuring process or the possible related impact on REMA. PSEG continues to monitor any changes to REMA’s and GenOn’s status and potential impacts on Energy Holdings’ lease investments and continues to discuss the situation with GenOn. If lease rejections or foreclosures were to occur, Energy Holdings could potentially record additional pre-tax write-offs up to its gross investment in these facilities and may also be required to accelerate and pay material deferred tax liabilities to the Internal Revenue Service (IRS).

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

Note ~~7. Available-for-Sale Securities~~9. Trust Investments

~~NDT~~Nuclear Decommissioning Trust (NDT) Fund

PSEG Power maintains an external master NDT to fund its share of decommissioning costs for its ~~five~~5 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. The funds are managed by third-party investment managers who operate under investment guidelines developed by PSEG Power.

~~Power classifies investments in the NDT Fund as available-for-sale.~~

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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

As of September 30, 2017
Cost
Gross
Unrealized
Gains

Gross
Unrealized
Losses

Fair
Value

Millions
Equity Securities $ 706
$ 331
$ (5 ) $ 1,032

Debt Securities
Government 561
10
(4 ) 567

Corporate 352
7
(1 ) 358

Total Debt Securities 913
17
(5 ) 925

Other Securities 55
—
—
55

Total NDT Available-for-Sale Securities $ 1,674
$ 348
$ (10 ) $ 2,012

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(UNAUDITED)~~

As of December 31, 2016
Cost
Gross
Unrealized
Gains

Gross
Unrealized
Losses

Fair
Value

Millions
Equity Securities $ 705
$ 263
$ (11 ) $ 957

Debt Securities
Government 518
8
(6 ) 520

Corporate 337
4
(4 ) 337

Total Debt Securities 855
12
(10 ) 857

Other Securities 44
—
—
44

Total NDT Available-for-Sale Securities (A) $ 1,604
$ 275
$ (21 ) $ 1,858




	As of September 30, 2019
	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	Millions
Equity Securities
Domestic	$	444	$	195	$	(7	)	$	632
International	387		71		(18		)	440
Total Equity Securities	831		266		(25		)	1,072
Available-for Sale Debt Securities
Government	544		22		—			566
Corporate	480		18		(2		)	496
Total Available-for-Sale Debt Securities	1,024		40		(2		)	1,062
Total NDT Fund Investments (A)	$	1,855	$	306	$	(27	)	$	2,134


(A)	The NDT ~~available-for-sale securities~~Fund Investments table excludes ~~cash~~foreign currency of $1 million as of September 30, 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

Net unrealized gains (losses) on debt securities of $22 million (after-tax) were included in Accumulated Other Comprehensive Loss on PSEG’s and PSEG Power’s Condensed Consolidated Balance Sheets as of September 30, 2019. The portion of net unrealized gains (losses) recognized during the third quarter and first nine months of 2019 related to equity securities still held as of September 30, 2019 was $(9) million and $102 million, respectively.

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 Condensed Consolidated Balance Sheets as shown in the following table.




	As of		As of
	September 30, 2019		December 31, 2018
	Millions
Accounts Receivable	$	14	$	17
Accounts Payable	$	13	$	5

As of As of
September 30,
2017 December 31,
2016
Millions
Accounts Receivable $ 11
$ 8

Accounts Payable $ 5
$ 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.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

As of September 30, 2017 As of December 31, 2016

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) $ 67
$ (5 ) $ —
$ —
$ 120
$ (10 ) $ 8
$ (1 )
Debt Securities
Government (B) 237
(2 ) 62
(2 ) 276
(6 ) 4
—

Corporate (C) 60
—
36
(1 ) 139
(3 ) 15
(1 )
Total Debt Securities 297
(2 ) 98
(3 ) 415
(9 ) 19
(1 )
Other Securities 3
—
—
—
—
—
—
—

NDT Available-for-Sale Securities $ 367
$ (7 ) $ 98
$ (3 ) $ 535
$ (19 ) $ 27
$ (2 )




	As of September 30, 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	$	69	$	(5	)	$	6	$	(2	)	$	147	$	(26	)	$	5	$	(3	)
International	45		(4		)	39		(14		)	131		(28		)	5		(2		)
Total Equity Securities	114		(9		)	45		(16		)	278		(54		)	10		(5		)
Available-for Sale Debt Securities
Government (B)	36		—			43		—			51		—			317		(9		)
Corporate (C)	36		—			19		(2		)	150		(5		)	222		(10		)
Total Available-for-Sale Debt Securities	72		—			62		(2		)	201		(5		)	539		(19		)
NDT Trust Investments	$	186	$	(9	)	$	107	$	(18	)	$	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. ~~The unrealized~~Unrealized gains and losses ~~are distributed over a broad range of securities with limited impairment durations. Power does not consider~~on these securities ~~to be other-than-temporarily impaired as of September 30, 2017.~~are recorded in Net Income.

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(UNAUDITED)~~

table ~~were recognized in Other Income and Other Deductions, respectively, in PSEG’s and Power’s Condensed Consolidated Statements~~ of ~~Operations. Net unrealized gains of~~ ~~$172 million~~ ~~(after-tax) were recognized in Accumulated Other Comprehensive Loss on PSEG’s and Power’s Condensed Consolidated Balance Sheets as of~~ ~~September 30, 2017~~.contents

(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 September 30, ~~2017.~~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 September 30, ~~2017.~~2019.

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

Three Months Ended Nine Months Ended
September 30, September 30,
2017 2016 2017 2016
Millions
Proceeds from NDT Fund Sales (A) $ 278
$ 139
$ 845
$ 470

Net Realized Gains (Losses) on NDT Fund:
Gross Realized Gains $ 29
$ 11
$ 82
$ 36

Gross Realized Losses (5 ) (3 ) (14 ) (25 )
Net Realized Gains (Losses) on NDT Fund $ 24
$ 8
$ 68
$ 11




	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2019			2018			2019			2018
	Millions
Proceeds from NDT Fund Sales (A)	$	365		$	231		$	1,245		$	1,005
Net Realized Gains (Losses) on NDT Fund
Gross Realized Gains	$	27		$	17		$	90		$	75
Gross Realized Losses	(11		)	(7		)	(43		)	(29		)
Net Realized Gains (Losses) on NDT Fund (B)	$	16		$	10		$	47		$	46
Unrealized Gains (Losses) on Equity Securities in NDT Fund	(21		)	$	34		111			(16		)
Net Gains (Losses) on NDT Fund Investments	$	(5	)	$	44		$	158		$	30

(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.

~~Gross realized gains and gross realized losses disclosed in the preceding~~

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

The NDT ~~available-for-sale~~Fund debt securities held as of September 30, ~~2017~~2019 had the following maturities:




Time Frame	Fair Value
	Millions
Less than one year	$	26
1 - 5 years	267
6 - 10 years	192
11 - 15 years	55
16 - 20 years	74
Over 20 years	448
Total NDT Available-for-Sale Debt Securities	$	1,062

Time Frame Fair Value
Millions
Less than one year $ 37

1 - 5 years 236

6 - 10 years 230

11 - 15 years 62

16 - 20 years 67

Over 20 years 293

Total NDT Available-for-Sale Debt Securities $ 925

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 ~~equity securities, management considers the ability and intent to hold for a reasonable time to permit recovery in addition to the severity and duration of the loss. For fixed income~~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). ~~For the nine months ended September 30, 2017, Other-Than-Temporary Impairments (OTTI) of$9 million~~ ~~were recognized on securities in the NDT Fund.~~ Any subsequent recoveries in the value of these securities would be

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(UNAUDITED)~~

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.”

~~PSEG classifies investments in the Rabbi Trust as available-for-sale.~~ 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 September 30, 2017
Cost
Gross
Unrealized
Gains

Gross
Unrealized
Losses

Fair
Value

Millions
Equity Securities $ 22
$ 1
$ —
$ 23

Debt Securities
Government 82
2
—
84

Corporate 118
3
(1 ) 120

Total Debt Securities 200
5
(1 ) 204

Other Securities 2
—
—
2

Total Rabbi Trust Available-for-Sale Securities $ 224
$ 6
$ (1 ) $ 229




	As of September 30, 2019
	Cost		Gross Unrealized Gains		Gross Unrealized Losses		Fair Value
	Millions
Domestic Equity Securities	$	20	$	5	$	—	$	25
Available-for-Sale Debt Securities
Government	101		8		—		109
Corporate	105		7		—		112
Total Available-for-Sale Debt Securities	206		15		—		221
Total Rabbi Trust Investments	$	226	$	20	$	—	$	246

As of December 31, 2016
Cost
Gross
Unrealized
Gains

Gross
Unrealized
Losses

Fair
Value

Millions
Equity Securities $ 11
$ 11
$ —
$ 22

Debt Securities
Government 105
—
(2 ) 103

Corporate 92
1
(2 ) 91

Total Debt Securities 197
1
(4 ) 194

Other Securities 1
—
—
1

Total Rabbi Trust Available-for-Sale Securities $ 209
$ 12
$ (4 ) $ 217

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)




	As of December 31, 2018
	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	Millions
Domestic 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 $11 million (after-tax) were included in Accumulated Other Comprehensive Loss on PSEG’s Condensed Consolidated Balance Sheet as of September 30, 2019. The portion of net unrealized gains (losses) recognized during the third quarter and first nine months of 2019 related to equity securities still held as of September 30, 2019 was less than $1 million and $4 million, respectively.

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 Condensed Consolidated Balance Sheets as shown in the following table.




	As of		As of
	September 30, 2019		December 31, 2018
	Millions
Accounts Receivable	$	2	$	2
Accounts Payable	$	—	$	—

As of As of
September 30,
2017 December 31,
2016
Millions
Accounts Receivable $ 2
$ 5

Accounts Payable $ —
$ 3

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(UNAUDITED)~~

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




	As of September 30, 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)	$	10	$	—	$	5	$	—	$	18	$	—		$	59	$	(2	)
Corporate (B)	9		—		4		—		50		(3		)	29		(1		)
Total Available-for-Sale Debt Securities	19		—		9		—		68		(3		)	88		(3		)
Rabbi Trust Investments	$	19	$	—	$	9	$	—	$	68	$	(3	)	$	88	$	(3	)

As of September 30, 2017 As of December 31, 2016

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) $ —
$ —
$ —
$ —
$ —
$ —
$ —
$ —

Debt Securities
Government (B) 25
—
3
—
60
(2 ) 1
—

Corporate (C) 14
(1 ) 4
—
46
(2 ) 3
—

Total Debt Securities 39
(1 ) 7
—
106
(4 ) 4
—

Rabbi Trust Available-for-Sale Securities $ 39
$ (1 ) $ 7
$ —
$ 106
$ (4 ) $ 4
$ —


(A)	Equity Securities—Investments in marketable equity securities within the Rabbi Trust Fund are through a mutual fund which invests primarily in common stocks within a broad range of industries and sectors.

~~(B)~~

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 September 30, 2017.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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 September 30, 2019.

~~(C)~~(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 September 30, ~~2017.~~2019.

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




	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2019			2018			2019			2018
	Millions
Proceeds from Rabbi Trust Sales (A)	$	43		$	33		$	129		$	80
Net Realized Gains (Losses) on Rabbi Trust:
Gross Realized Gains	$	3		$	—		$	5		$	2
Gross Realized Losses	(2		)	(1		)	(3		)	(3		)
Net Realized Gains (Losses) on Rabbi Trust (B)	1			(1		)	2			(1		)
Unrealized Gains (Losses) on Equity Securities in Rabbi Trust	1			2			4			2
Net Gains (Losses) on Rabbi Trust Investments	$	2		$	1		$	6		$	1

Three Months Ended Nine Months Ended
September 30, September 30,
2017 2016 2017 2016
Millions
Proceeds from Rabbi Trust Sales (A) $ 24
$ 20
$ 168
$ 81

Net Realized Gains (Losses) on Rabbi Trust:
Gross Realized Gains $ —
$ 2
$ 17
$ 5

Gross Realized Losses (1 ) (2 ) (5 ) (4 )
Net Realized Gains (Losses) on Rabbi Trust $ (1 ) $ —
$ 12
$ 1

(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.

Gross realized gains and gross realized losses disclosed in the preceding table were recognized in Other Income and Other Deductions, respectively, in the Condensed Consolidated Statements of Operations. Net unrealized gains of $3 million (after-tax) were recognized in Accumulated Other Comprehensive Loss on the Condensed Consolidated Balance Sheets as of ~~September 30, 2017~~.

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(UNAUDITED)~~

The Rabbi Trust ~~available-for-sale~~ debt securities held as of September 30, ~~2017~~2019 had the following maturities:




Time Frame	Fair Value
	Millions
Less than one year	$	4
1 - 5 years	30
6 - 10 years	33
11 - 15 years	12
16 - 20 years	27
Over 20 years	115
Total Rabbi Trust Available-for-Sale Debt Securities	$	221

Time Frame Fair Value
Millions
Less than one year $ —

1 - 5 years 40

6 - 10 years 27

11 - 15 years 6

16 - 20 years 19

Over 20 years 112

Total Rabbi Trust Available-for-Sale Debt Securities $ 204

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 ~~equity securities, the Rabbi Trust is invested in an indexed mutual fund. Due to the commingled nature of this fund, PSEG does not have the ability to hold~~ these ~~securities until expected recovery. As a result, any declines in fair market value below cost are recorded as a charge to earnings. For fixed income~~ 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). ~~For the nine months ended September 30, 2017, no OTTIs were recognized on securities in the Rabbi Trust.~~ 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.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

The fair value of the Rabbi Trust related to PSEG, PSE&G and PSEG Power are detailed as follows:




	As of		As of
	September 30, 2019		December 31, 2018
	Millions
PSE&G	$	48	$	45
PSEG Power	62		56
Other	136		123
Total Rabbi Trust Investments	$	246	$	224

As of As of
September 30,
2017 December 31,
2016
Millions
PSE&G $ 46
$ 43

Power 57
53

Other 126
121

Total Rabbi Trust Available-for-Sale Securities $ 229
$ 217

Note 8.10. Pension and Other Postretirement Benefits (OPEB)

PSEG sponsors qualified and nonqualified pension plans and OPEB plans covering PSEG’s and its participating affiliates’ current and former employees who meet certain eligibility criteria.

In late June 2019, PSEG approved a plan amendment to its qualified pension plan, effective July 1, 2019. The amendment involved the spin-off of predominantly active participants from the existing qualified pension plan into a new qualified pension plan. Benefits offered to the plan participants remain unchanged. As a result of the amendment, the existing plan’s pension benefit obligations, as well as the asset values, were remeasured as of July 1, 2019. The weighted average discount rate for the combined plans decreased from 4.41% to 3.65%. The expected long-term rate of return on plan assets remains at 7.80%. Actuarial gains and losses associated with the existing 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 the new plan 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, 2016, PSEG merged its three qualified defined benefit pension plans (excluding Servco plans) into one plan, thereby also merging all of the pension plans’ assets. As a result, the total net periodic benefit costs, net of amounts capitalized, decreased by approximately $12 million and $36 million for the three months and nine months, ended September 30, 2017, respectively, as compared to the 2017 amounts that would have been recognized had the plans not been merged. This is due to the amortization period for gains and losses for the merged plan resulting in lower amortization than that of the individual plans. No changes were made to the benefit formulas, vesting provisions, or to the employees covered by the plans.2018.

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(UNAUDITED)~~

The following table provides the components of net periodic benefit costs relating to all qualified and nonqualified pension and OPEB plans on an aggregate basis for PSEG, excluding Servco. Amounts shown do not reflect the impacts of capitalization and co-owner allocations. Only the service cost component is eligible for capitalization, when applicable.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Pension Benefits OPEB Pension Benefits OPEB
Three Months Ended Three Months Ended Nine Months Ended Nine Months Ended
September 30, September 30, September 30, September 30,
2017
2016 2017
2016 2017 2016 2017 2016
Millions
Components of Net Periodic Benefit Costs
Service Cost $ 29
$ 28
$ 4
$ 5
$ 86
$ 82
$ 12
$ 13

Interest Cost 51
50
15
15
153
151
47
44

Expected Return on Plan Assets (98 ) (98 ) (8 ) (8 ) (295 ) (295 ) (25 ) (23 )
Amortization of Net
Prior Service Cost (Credit) (5 ) (5 ) (3 ) (4 ) (14 ) (14 ) (8 ) (11 )
Actuarial Loss 24
39
13
10
73
118
38
30

Total Benefit Costs $ 1
$ 14
$ 21
$ 18
$ 3
$ 42
$ 64
$ 53




	Pension Benefits						OPEB						Pension Benefits						OPEB
	Three Months Ended						Three Months Ended						Nine Months Ended						Nine Months Ended
	September 30,						September 30,						September 30,						September 30,
	2019			2018			2019			2018			2019			2018			2019			2018
	Millions
Components of Net Periodic Benefit (Credits) Costs
Service Cost (included in O&M Expense)	$	33		$	32		$	2		$	4		$	90		$	97		$	7		$	13
Non-Service Components of Pension and OPEB (Credits) Costs
Interest Cost	51			52			12			16			167			156			34			49
Expected Return on Plan Assets	(108		)	(111		)	(9		)	(9		)	(301		)	(331		)	(27		)	(30		)
Amortization of Net
Prior Service Credit	(4		)	(4		)	(32		)	(1		)	(13		)	(13		)	(96		)	(1		)
Actuarial Loss	21			22			13			16			75			64			38			48
Non-Service Components of Pension and OPEB (Credits) Costs	(40		)	(41		)	(16		)	22			(72		)	(124		)	(51		)	66
Total Benefit (Credits) Costs	$	(7	)	$	(9	)	$	(14	)	$	26		$	18		$	(27	)	$	(44	)	$	79

Pension and OPEB costs for PSE&G, PSEG Power and PSEG’s other subsidiaries, excluding Servco, are detailed as follows:




	Pension Benefits						OPEB					Pension Benefits					OPEB
	Three Months Ended						Three Months Ended					Nine Months Ended					Nine Months Ended
	September 30,						September 30,					September 30,					September 30,
	2019			2018			2019			2018		2019		2018			2019			2018
	Millions
PSE&G	$	(6	)	$	(8	)	$	(14	)	$	17	$	7	$	(23	)	$	(46	)	$	51
PSEG Power	(2		)	(2		)	—			8		5		(7		)	2			24
Other	1			1			—			1		6		3			—			4
Total Benefit (Credits) Costs	$	(7	)	$	(9	)	$	(14	)	$	26	$	18	$	(27	)	$	(44	)	$	79

Pension Benefits OPEB Pension Benefits OPEB
Three Months Ended Three Months Ended Nine Months Ended Nine Months Ended
September 30, September 30, September 30, September 30,
2017 2016 2017 2016 2017 2016 2017 2016
Millions
PSE&G $ (1 ) $ 8
$ 13
$ 11
$ (3 ) $ 22
$ 40
$ 33

Power —
3
7
6
1
11
20
17

Other 2
3
1
1
5
9
4
3

Total Benefit Costs $ 1
$ 14
$ 21
$ 18
$ 3
$ 42
$ 64
$ 53

During the three months ended March 31, ~~2017,~~2019, PSEG contributed its entire 2019 annual planned contribution ~~for the year 2017~~ of ~~$14~~$10 million into its OPEB plan.

Servco Pension and OPEB

At the direction of LIPA, Servco sponsors benefit plans that cover its current and former employees who meet certain eligibility criteria. Under the OSA, all of these and any future employee benefit costs are to be funded by LIPA. See Note 4.5. Variable Interest Entity. These obligations, as well as the offsetting long-term receivable, are separately presented on the Condensed Consolidated Balance Sheet of PSEG.

Servco amounts are not included in any of the preceding pension and OPEB ~~benefit~~ cost disclosures. 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. Servco’s pension-related revenues and costs were ~~$18~~$14 million and ~~$16 million for the three months ended September 30, 2017 and 2016, respectively, and $35 million and~~ $28 million for the nine months ended September 30, 2017 and 2016, respectively. Servco’s pension-related costs of $35 million for the nine months ended September 30, 2017 represent its entire planned contribution for the year 2017. The OPEB-related revenues earned and costs incurred were $1 million and $3 million for the three months and nine months ended September 30, ~~2017. The OPEB-related~~2019, respectively. As of September 30, 2019, Servco completed its entire 2019 annual planned contribution into its pension plan. Servco’s pension-related revenues ~~earned~~ and costs ~~incurred~~ were ~~immaterial~~$20 million and $40 million for the three months and nine months ended September 30, ~~2016.~~2018, respectively. The OPEB-related revenues earned and costs incurred were $1 million for each of the three months ended September 30, 2019 and 2018, and $4 million for each of the nine months ended September 30, 2019 and 2018.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Note 9.11. 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 by 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, 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).

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 ~~contractual~~ obligations.

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(UNAUDITED)~~

The following table shows the face value of PSEG Power’s outstanding guarantees, current exposure and margin positions as of September 30, ~~2017~~2019 and December 31, ~~2016.~~2018.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

As of As of
September 30,
2017 December 31,
2016
Millions
Face Value of Outstanding Guarantees $ 1,846
$ 1,806

Exposure under Current Guarantees $ 108
$ 139

Letters of Credit Margin Posted $ 134
$ 157

Letters of Credit Margin Received $ 59
$ 99

Cash Deposited and Received:
Counterparty Cash Margin Deposited $ —
$ —

Counterparty Cash Margin Received $ (2 ) $ (1 )
Net Broker Balance Deposited (Received) $ (6 ) $ 57

Additional Amounts Posted:
Other Letters of Credit $ 61
$ 51




	As of			As of
	September 30, 2019			December 31, 2018
	Millions
Face Value of Outstanding Guarantees	$	1,827		$	1,772
Exposure under Current Guarantees	$	134		$	198

Letters of Credit Margin Posted	$	137		$	115
Letters of Credit Margin Received	$	34		$	26

Cash Deposited and Received:
Counterparty Cash Margin Deposited	$	—		$	—
Counterparty Cash Margin Received	$	(3	)	$	(10	)
Net Broker Balance Deposited (Received)	$	95		$	403

Additional Amounts Posted:
Other Letters of Credit	$	53		$	52

As part of determining credit exposure, PSEG Power nets receivables and payables with the corresponding net fair values of energy ~~contract balances.~~contracts. See Note ~~11.~~13. 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 Condensed 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. PSEG also issued a $21 million guarantee to support Power’s payment obligations related to construction of a 755 MW gas-fired combined cycle generating station in Maryland. In the event that PSEG were to be downgraded to below investment grade and failed to meet minimum net worth requirements, these guarantees would each have to be replaced by a letter of credit. In June 2017, Power sold its minority equity interest in PennEast and upon disposition, PSEG’s $106 million guarantee that had supported Power’s obligations related to PennEast was terminated.

Environmental Matters

Passaic River

~~Historic operations~~Lower Passaic River Study Area

The U.S. Environmental Protection Agency (EPA) has determined that a 17-mile stretch of ~~PSEG companies 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~~River (Lower Passaic River Study Area (LPRSA)) in New Jersey is a “Superfund” site under the ~~Passaic River/Newark Bay Complex in violation of various statutes as discussed as follows.~~

Federal Comprehensive Environmental Response, Compensation and Liability Act of 1980 (CERCLA)

In 2002, the EPA determined that a 17-mile stretch of the lower Passaic River from Newark to Clifton, New Jersey is a “Superfund” site under CERCLA. This designation allows the EPA to clean up such sites and to compel responsible parties to perform cleanups or reimburse the government for cleanups led by the EPA.

~~The EPA determined that there was a need to perform a comprehensive study of the entire 17 miles of the lower Passaic River.~~. PSE&G and certain of its predecessors conducted operations at properties in this area, ~~of the Passaic River. The properties included one operating electric generating station (Essex Site), which~~including at 1 site that was transferred to ~~Power, one former generating station and four former manufactured gas plant (MGP) sites.~~PSEG Power.

~~In early 2007, 73~~Certain Potentially Responsible Parties (PRPs), including PSE&G and PSEG Power, formed a Cooperating Parties Group (CPG) and agreed to ~~assume responsibility for conducting~~conduct a Remedial Investigation and Feasibility Study ~~(RI/FS)~~ of the ~~17 miles of the lower Passaic River. At such time, the~~LPRSA. The CPG ~~also agreed to allocate,~~allocated, on an interim basis, the associated costs ~~of the~~

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(UNAUDITED)~~

~~RI/FS~~ among its ~~members on the basis of a mutually agreed upon formula. For the purpose of this~~members. The interim allocation ~~which has been revised as parties have exited~~is subject to change. In June 2019, the EPA conditionally approved the CPG’s Remedial Investigation. In August 2019, the CPG ~~approximately seven percent~~submitted a draft Feasibility Study to the EPA which evaluated various adaptive management scenarios for the remediation of only the RI/FS costs are currently deemed attributable to PSE&G’s former MGP sites and approximately one percent is attributable to Power’s generating stations. These interim allocations are not binding on PSE&G or Power in terms of their respective shares of the costs that will be ultimately required to remediate the 17upper 9 miles of the ~~lower Passaic River. PSEG has provided notice to insurers concerning this potential claim.~~LPRSA.

~~In June 2008,~~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. The litigation is ongoing and PSEG cannot predict the outcome.

Two PRPs, Tierra Solutions, Inc. (Tierra) and Maxus Energy Corporation (Maxus) ~~entered into an early action agreement whereby Tierra/Maxus agreed to remove a portion of~~, have filed for Chapter 11 bankruptcy. The trust representing the ~~heavily dioxin-contaminated sediment located in the lower Passaic River. The portion of the Passaic River identified~~creditors in this ~~agreement was located immediately adjacent to Tierra/~~proceeding has filed a complaint asserting claims against Tierra’s and Maxus’ ~~predecessor company’s (Diamond Shamrock) facility. Pursuant to the agreement between the EPA~~current and Tierra/Maxus, the estimated cost for the work to remove the sediment in this location was $80 million. Phase I of the removal work has been completed. Pursuant to this agreement, Tierra/Maxus have reserved their rights to seek contribution for these removal costs from the other PRPs, including Power and PSE&G.

~~In 2012, Tierra/Maxus withdrew from the CPG and refused to participate as members going forward, other than with respect to their obligation~~former parent entities, among others. Any damages awarded may be used to fund the ~~EPA’s portion of its RI/FS oversight costs. At such time, the remaining members~~remediation of the CPG, in agreement with the EPA, commenced the removal of certain contaminated sediments at Passaic River Mile 10.9 at an estimated cost of $25 million to $30 million. Construction is complete. The CPG is awaiting EPA approval of the construction report, long-term monitoring plan and confirmatory sampling plan. PSE&G’s and Power’s combined share of the cost of that effort is approximately three percent. The remaining CPG members, PSE&G and Power included, have reserved their rights to seek reimbursement from Tierra/Maxus for the costs of the River Mile 10.9 removal.LPRSA.

On April 11, 2014, the EPA released its revised draft “Focused Feasibility Study” (FFS) which contemplates the removal of 4.3 million cubic yards of sediment from the bottom of the lower eight miles of the 17-mile stretch of the Passaic River. The revised draft FFS sets forth various alternatives for remediating this portion of the Passaic River.

~~The CPG, which consisted of 50 members as~~As of September 30, 2017, provided a draft RI and draft FS, both relating to the entire 17 miles of the lower Passaic River, to the EPA on February 18, 2015 and April 30, 2015, respectively. The estimated total cost of the RI/FS is2019, PSEG has accrued approximately ~~$195~~$65 million ~~which the CPG continues to incur.~~for this matter. Of ~~the estimated $195~~this amount, PSE&G has accrued $52 million as ~~of September 30, 2017, the CPG had spent approximately $168 million, of which PSEG’s total share was approximately $12 million.~~

The CPG’s draft FS set forth various alternatives for remediating the lower Passaic River. It set forth the CPG’s estimated costs to remediate the lower 17 miles of the Passaic River which range from approximately $518 million to $3.2 billion on an undiscounted basis. The CPG identified a targeted remedy in the draft FS which would involve removal, treatment and disposal of contaminated sediments taken from targeted locations within the entire 17 miles of the lower Passaic River. The estimated cost in the draft FS for the targeted remedy ranged from approximately $518 million to $772 million. Based on (i) the low end of the range of the current estimates of costs to remediate, (ii) PSE&G’s and Power’s estimated share of those costs, and (iii) the continued ability of PSE&G to recover such costs in its rates, PSE&G accrued a $10 million Environmental Costs Liability and a corresponding Regulatory Asset ~~and Power accrued a $3 million Other Noncurrent Liability and a corresponding O&M Expense in the first quarter of 2015.~~

~~In March 2016, the EPA released~~based on its Record of Decision (ROD) for the FFS which requires the removal of 3.5 million cubic yards of sediment from the Passaic River’s lower 8.3 miles at an estimated cost of $2.3 billion on an undiscounted basis (ROD Remedy). The ROD Remedy requires a bank-to-bank dredge ranging from approximately 5 to 30 feet deep in the federal navigation channel from River Mile 0 to River Mile 1.7 and an approximately 2.5 foot deep dredge everywhere else in the lower 8.3 miles of the river. An engineered cap approximately two feet thick will be placed over the dredged areas. Dredged sediments will be transported to facilities and landfills out-of-state. The EPA estimates the total project length to be about 11 years, including a one year period of negotiation with the PRPs, three to four years to design the project and six years for implementation.

~~Based upon the estimated cost of the ROD Remedy, PSEG’s estimate of PSE&G’s and Power’s shares of that cost, and the~~ continued ability ~~of PSE&G~~ to recover such costs in its ~~rates, PSE&G~~rates. PSEG Power has accrued ~~an additional $36~~$13 million ~~Environmental Costs Liability and a corresponding Regulatory Asset and Power accrued~~as an ~~additional $8 million~~ Other Noncurrent Liability ~~and a~~with the corresponding O&M ~~Expense in the first quarter~~Expense.

The outcome of ~~2016. These accruals brought the total liability to approximately $57 million, $46 million applicable to PSE&G~~this matter is uncertain, and ~~$11 million applicable to Power. There have been no additional accruals recorded since the first quarter of 2016.~~

~~Also in March 2016, the EPA sent~~until (i) a notice letter to 105 PRPs, including PSE&G, all other past and present members of the CPG, including Occidental Chemical Corporation (OCC), and the towns of Newark, Kearny and Harrison and the Passaic Valley Sewerage Commission stating that the EPA wants to determine whether OCC, a successor company to Diamond Shamrock, would voluntarily perform the remedial designfinal remedy for the ~~ROD Remedy. On September 30, 2016, OCC~~entire LPRSA is selected and ~~the EPA~~

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(UNAUDITED)~~

executed an Administrative Settlement Agreement and Order on Consent for Remedial Design under which OCC agreed to conduct the remedial design for the ROD. With OCC’s commitment to perform the remedial design, it is anticipated that the EPA will begin negotiation of a remedial action consent decree, under which OCC and the other “major PRPs” will implement and/or pay for the EPA’s ROD Remedy for the lower 8.3 miles. The EPA has not defined “major PRPs.”

In June 2016, Tierra and Maxus, successors to Diamond Shamrock, filed for reorganization under Chapter 11 of the U.S. Bankruptcy Code. Maxus and Tierra are subsidiaries of YPF Holdings, Inc. (YPF Holdings). YPF Holdings is a wholly owned subsidiary of YPF S.A. (YPF), a company controlled by the Argentinian government. Neither YPF Holdings nor YPF is a party to the bankruptcy proceedings. However, Tierra and Maxus have filed a plan of liquidation that may allow the parties to assert one or more causes of action to hold YPF responsible for certain amounts owed by Tierra and Maxus. The bankruptcy plan ordered by the Delaware Court in July, 2017 created a Liquidating Trust to pursue outstanding creditors’ claims, including alter ego claims against YPF. PSEG cannot currently determine the impact, if any, that the bankruptcy of Tierra and Maxus or any related proceeding might have on its allocable share or total liability for the Passaic River matter, and therefore, PSEG, through the CPG and independently, will continue to monitor the bankruptcy proceedings to identify any potential impact on PSEG’s share of the costs.

In March 2017, the EPA sent a letter to certain PRPs that are considered by the EPA to have minimal responsibility for the Passaic River’s contamination, offering “cash-out” settlements. The PRPs that settle will be released from their CERCLA remediation liability for the lower 8.3 miles of the lower Passaic River. The impact of this proposed settlement on PSEG’s responsibility for the remediation of the lower 8.3 miles is not material.

In September 2017, the EPA concluded that an Agency-commenced allocation process for the Passaic River’s lower 8.3 miles should include only certain PRPs that received General Notice letters (excluding PRPs that settle pursuant to the early cash-out settlement that the EPA offered in March 2017, among others). The allocation is intended to lead to a consent decree in which certain of the PRPs agree to perform the remedial action under EPA oversight. Discussions on the matter are ongoing.

The EPA has broad authority to implement its selected remedy through the ROD and PSEG cannot at this time predict how the implementation of the ROD might impact PSE&G’s and Power’s ultimate liability. Until (i) the RI/FS, which covers the entire 17 miles of the lower Passaic River, is finalized either in whole or in part, (ii) an agreement reached by the PRPs to ~~perform either the ROD Remedy as issued, or an amended ROD Remedy determined through negotiation or litigation, and an agreed upon remedy for the remaining 8.7 miles of the river, are reached, (iii)~~fund it, (ii) PSE&G’s and PSEG Power’s respective shares of the costs ~~both in the aggregate as well as individually,~~ are determined, and ~~(iv)~~(iii) PSE&G’s continued ability to recover the costs in its rates is determined, it is not possible to predict this matter’s ultimate impact on

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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

~~In 2003, the~~ New Jersey ~~Department of Environmental Protection (NJDEP) directed~~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. PSE&G and 56 other PRPs to arrange for a natural resource damage assessment and interim compensatory restoration of natural resource injuries along the lower Passaic River and its tributaries pursuant to the New Jersey Spill Compensation and Control Act. The NJDEP alleged that hazardous substances had been discharged from the Essex Site and the Harrison Site. The NJDEP estimated the cost of interim natural resource injury restoration activities along the lower Passaic River at approximately $950 million. In 2007, agencies of the U.S. Department of Commerce and the U.S. Department of the Interior (the Passaic River federal trustees) sent letters to PSE&G and other PRPs inviting participation in an assessment of injuries to natural resources that the agencies intended to perform. In 2008, PSEG and a number of other PRPs agreed to share certain immaterial costs the trustees have incurred and will incur going forward, and to work with the trustees to explore whether some or all of the trustees’ claims can be resolved in a cooperative fashion. That effort is continuing. PSE&G and Power are unable to estimate their respective portions of ~~the~~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 ~~it defines as~~is an extension of the LPRSA and includes Newark Bay and portions of ~~the Hackensack River, the Arthur Kill and the Kill Van Kull. In August 2006, the~~surrounding waterways. The EPA ~~sent~~has notified PSEG and 11 other ~~entities notices that it considered each~~PRPs of the entities to be a PRP with respect to contamination in the Study Area. The notice letter requested that the PRPs fund an EPA-approved study in the Newark Bay Study Area. The notice stated the EPA’s belief that hazardous substances were released from sites owned by PSEG companies and located on the Hackensack River, including two operating electric generating stations (Hudson and Kearny sites) and one former MGP site. PSEG has participated in and partially funded the second phase of this study. Notices to fund the next phase of the study have been received but PSEG has not consented to fund the third phase.their potential liability. PSE&G and PSEG Power are unable to estimate their respective portions of ~~the possible~~any loss or possible range of loss related to this matter.

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(UNAUDITED)~~

~~Table~~ In December 2018, PSEG Power completed the sale of ~~Contents~~

the site of the Hudson electric generating station. PSEG Power contractually transferred all land rights and structures on the 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 ~~NJDEP~~New Jersey Department 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 ~~$390~~$364 million and ~~$440~~$407 million on an undiscounted basis through~~2021,~~2023, including its ~~$46~~$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 ~~$390~~$364 million as ofSeptember 30, ~~2017.~~2019. Of this amount, ~~$74~~$69 million was recorded in Other Current Liabilities and ~~$316~~$295 million was reflected as Environmental Costs in Noncurrent Liabilities. PSE&G has recorded a ~~$390~~$364 millionRegulatory 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. ~~NJDEP, PSEG and EPA representatives have had discussions regarding~~PSE&G has agreed to ~~what extent~~conduct sampling in the Passaic River ~~is required~~ 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.

~~Prevention of Significant Deterioration (PSD)/New Source Review (NSR)~~

The PSD/NSR regulations, promulgated under the Clean Air Act (CAA), require major sources of certain air pollutants to obtain permits, install pollution control technology and obtain offsets, in some circumstances, when those sources undergo a “major modification,” as defined in the regulations. The federal government may order companies that are not in compliance with the PSD/NSR regulations to install the best available control technology at the affected plants and to pay monetary penalties ranging from $25,000 to $37,500 per day for each violation, depending upon when the alleged violation occurred.

In 2009, the EPA issued a notice of violation to Power and the other owners of the Keystone coal-fired plant in Pennsylvania, alleging, among other things, that various capital improvement projects were completed at the plant which are considered modifications (or major modifications) causing significant net emission increases of PSD/NSR air pollutants, beginning in 1985 for Keystone Unit 1 and in 1984 for Keystone Unit 2. The notice of violation states that none of these modifications underwent the PSD/NSR permitting process prior to being put into service, which the EPA alleges was required under the CAA. The notice of violation states that the EPA may issue an order requiring compliance with the relevant CAA provisions and may seek injunctive relief and/or civil penalties. Power owns approximately 23% of the plant. Power cannot predict the outcome of this matter.

Clean Water Act (CWA) ~~Permit Renewals~~Section 316(b) Rule

~~Pursuant to~~The EPA’s CWA Section 316(b) rule establishes requirements for the ~~Federal Water Pollution Control Act,~~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 ~~expire within~~be renewed every five years ~~of their effective date. In order to renew these~~and that each state Permitting Director manage renewal permits ~~but allow~~for its respective power generation facilities on a plant to continue to operate, an owner or operator must file a permit application no later than six months prior to expiration of the permit. States with delegated federal authority for this program manage these permits.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 May 2014, the EPA issued a final rule that establishes new requirements for the regulation of cooling water intake structures 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. In connection with the assessment of the best technology available for minimizing adverse environmental impacts of each facility that seeks a permit renewal, the rule requires that facilities conduct a wide range of studies related to impingement mortality and entrainment and submit the results with their permit applications.

In September 2014, several environmental non-governmental groups and certain energy industry groups filed petitions for review of the rule and the case has been assigned to the U.S. Court of Appeals for the Second Circuit (Second Circuit). Environmental organizations, including but not limited to the environmental petitioners in the Second Circuit, have also filed suit under the Endangered Species Act. The cases were subsequently consolidated at the Second Circuit and a decision remains pending.

In June 2016, the NJDEP issued a final NJPDES permit for Salem with an effective date of August 1, 2016. The final permit does not require installation of cooling towers and allows Salem to continue to operate utilizing the existing once-through cooling water system. The final permit does not mandate specific service water system modifications, but consistent with Section 316 (b) of the CWA, it requires additional studies and the selection of technology to address impingement for the service water system.Salem. In July 2016, the Delaware Riverkeeper Network (Riverkeeper) filed aan administrative hearing request challenging certain conditions of the permit, including the NJDEP’s ~~issuance~~application of the ~~final permit for Salem. This matter is still pending. The Riverkeeper’s filing does not change the effective date of the permit.~~316(b) rule. If the Riverkeeper’s challenge ~~were~~is successful, PSEG Power may be required to incur additional costs to comply with

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(UNAUDITED)~~

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 Bridgeport and ~~possibly~~ 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 ~~intake structures~~intakes and cooling systems.

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.

~~Power is actively engaged with the Connecticut Department of Energy and Environmental Protection (CTDEEP) regarding renewal of the current permit for the cooling water intake structure at BH3.~~ To address compliance with the EPA’s CWA Section 316(b) ~~final~~ rule ~~the current proposal under consideration is that, if a final permit is issued,~~at Bridgeport Harbor Station Unit 3 (BH3), PSEG Power ~~would~~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. ~~Power is currently awaiting action by the CTDEEP to issue a draft and then a final permit.~~

~~Separately,~~PSEG Power has ~~also negotiated~~entered into a Community Environmental Benefit Agreement (CEBA) with the City of Bridgeport, Connecticut and local community organizations. That CEBA provides that PSEG Power would retire BH3 early if all of its conditions precedent ~~conditions~~ occur, which include receipt of all final permits to build and operate a proposed new combined cycle generating facility on the same site that BH3 currently operates. Absent those conditions being met, and the permit for the

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

cooling water intake structure referred to above not being issued, PSEG Power may seek to operate BH3 through the previously estimated useful life.

In February 2016, the proposed new generating facility at Bridgeport Harbor was awarded a capacity obligation. The Connecticut Siting Council ~~(CSC)~~ issued an order to approve siting ~~Bridgeport Harbor Station unit 5. All major environmental permits have been received; however, secondary approvals are still being obtained to allow operations to begin by~~BH5. In June ~~2019.~~2019, BH5 began commercial operations. PSEG Power’s obligations under the CEBA are being monitored regularly and carried out as needed.

~~Bridgeport Harbor National Pollutant Discharge Elimination System (NPDES) Permit Compliance~~

In April 2015, Power determined that monitoring and reporting practices related to certain permitted wastewater discharges at its Bridgeport Harbor station may have violated conditions of the station’s NPDES permit and applicable regulations and could subject it to fines and penalties. Power has notified the CTDEEP of the issues and has taken actions to investigate and resolve the potential non-compliance. Power cannot predict the impact of this matter.

Jersey City, New Jersey Subsurface Feeder Cable Matter

In ~~early~~ 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 ~~has~~ declared an emergency and an emergency response action ~~has been~~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 regulatory agencies overseeing the emergency response, including the U.S. Coast Guard, the NJDEP and the Army Corps of Engineers, ~~have~~ issued multiple notices, orders and directives to the various parties related to this matter and the parties may also be subject to the assessment of civil penalties related to the discharge and response. The U.S. Coast Guard transitioned control of the federal response to the EPA in May 2018. In August 2018, the EPA ended the federal response to the matter. The response has now transitioned to the NJDEP site remediation program.

The impacted cable was repaired in ~~late-September~~late September 2017; however, small amounts of residual dielectric fluid believed to be contained within the ~~investigation~~marina sediment continue to appear on the surface and response actions related to the fluid discharge are ~~ongoing.~~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. PSE&G has been unable to reach an agreement with Con Edison and, as a result, in May 2018, PSE&G filed an action at FERC to resolve the matter. FERC dismissed PSE&G’s Complaint against Con Edison in September 2018 and PSE&G challenged FERC’s decision. In September 2019, FERC denied PSE&G’s challenge to the order dismissing the Complaint. Also ongoing is the ~~process~~lawsuit in federal court 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 ~~an action filed by PSE&G in New Jersey federal court~~ seeking ~~damages from NADC.~~injunctive relief and damages. Based on theinformation currently available and depending on the outcome of the ~~New Jersey~~ 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.

~~Steam Electric Effluent Guidelines~~

In September 2015, the EPA issued a new Effluent Limitation Guidelines Rule (ELG Rule) for steam electric generating units. The rule establishes new best available technology economically achievable (BAT) standards for fly ash transport water, bottom ash transport water, flue gas desulfurization and flue gas mercury control wastewater, and gasification wastewater. The EPA provides an implementation period for currently existing discharges of three years or up to eight years if a facility needs more time to implement equipment upgrades and provide supporting information to its permitting authority. In the intervening time period, existing discharge standards continue to apply. Power’s Bridgeport Harbor station and the jointly-owned Keystone and

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(UNAUDITED)~~

~~Conemaugh stations, have bottom ash transport water discharges that are regulated under this rule. Keystone and Conemaugh also have flue gas desulfurization wastewaters regulated by the rule.~~

In April 2017, the EPA announced that it had granted a petition for reconsideration of the ELG Rule and issued an administrative stay of the compliance dates in the rule that were the subject of pending litigation. In June 2017, the EPA proposed a rule to postpone the compliance deadlines for the BAT limitations for the aforementioned waste streams.In September 2017, the EPA issued a rule postponing for two years compliance dates solely related to bottom ash transport water and flue gas desulfurization wastewater. The EPA has announced plans to issue a new rule by November 2020 addressing revised requirements and compliance dates for these two waste streams. Power is unable to determine how this will ultimately impact its compliance requirements or its financial condition and results of operations.

Basic Generation Service (BGS), BGSS and ~~Basic Gas Supply Service (BGSS)~~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~~third-party suppliers. The first category, which represents about 80% of PSE&G’s load requirement, is residential and smaller commercial and industrial customers (BGS-Residential Small Commercial Pricing (RSCP)). The second category is larger customers that exceed a BPU-established load (kW) threshold (BGS-Commercial and Industrial Energy Pricing (CIEP)). Pursuant to applicable BPU rules, PSE&G enters into the Supplier Master 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~~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, ~~2016~~2019 is ~~$276.83~~$281.78 per MW-day, replacing the BGS-CIEP auction year price ending May 31, ~~2016~~2019 of ~~$335.33~~$287.76 per MW-day. Energy for BGS-CIEP is priced at hourly PJM locational marginal prices for the contract period.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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
	2016	2017	2018	2019
36-Month Terms Ending	May 2019	May 2020	May 2021	May 2022	(A)
Load (MW)	2,800	2,800	2,900	2,800
$ per MWh	$96.38	$90.78	$91.77	$98.04

Auction Year
2014 2015 2016 2017
36-Month Terms Ending May 2017
May 2018
May 2019
May 2020
(A)
Load (MW) 2,800
2,900
2,800
2,800

$ per MWh $97.39 $99.54 $96.38 $90.78


(A)	Prices set in the ~~2017~~2019 BGS auction ~~year~~ became effective on June 1, ~~2017~~2019 when the ~~2014~~2016 BGS auction agreements expired.

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 ~~electric distribution companies (EDCs)~~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 ~~18.~~20. 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 kilowatt-hour 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 ~~2020~~2021 and a significant portion through ~~2021~~2022 at Salem, Hope Creek and Peach Bottom.

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(UNAUDITED)~~

PSEG Power has various multi-year contracts for natural gas and firm ~~pipeline~~ transportation and storage capacity for natural gas that are primarily used to meet its obligations to PSE&G. When there is excess ~~pipeline~~delivery capacity available beyond the needs of PSE&G’s customers, PSEG Power can use the gas to ~~make third-party sales and if excess volume remains after the third-party sales,~~ supply its fossil generating stations in New Jersey.

~~Power also has various long-term fuel purchase commitments for coal through 2021 to support~~In connection with the sale of its ownership interests in the Keystone and Conemaugh ~~fossil~~ generation ~~stations.~~plants in September 2019, PSEG Power transferred the related coal purchase commitments to the buyers.

As of September 30, ~~2017,~~2019, the total minimum purchase requirements included in these commitments were as follows:




Fuel Type	PSEG Power's Share of Commitments through 2023
	Millions
Nuclear Fuel
Uranium	$	203
Enrichment	$	328
Fabrication	$	141
Natural Gas	$	1,082

Fuel Type Power's Share of Commitments through 2021
Millions
Nuclear Fuel
Uranium $ 257

Enrichment $ 328

Fabrication $ 178

Natural Gas $ 963

Coal $ 308

~~Regulatory Proceedings~~

~~FERC Compliance~~

~~PJM Bidding Matter~~

In the first quarter of 2014, Power discovered that it incorrectly calculated certain components of its cost-based bids for its New Jersey fossil generating units in the PJM energy market. Upon discovery of the errors, PSEG retained outside counsel to assist in the conduct of an investigation into the matter and self-reported the errors. As the internal investigation proceeded, additional pricing errors in the bids were identified. It was further determined that the quantity of energy that Power offered into the energy market for its fossil peaking units differed from the amount for which Power was compensated in the capacity market for those units. PSEG informed FERC, PJM and the PJM Independent Market Monitor (IMM) of these additional issues, corrected the identified errors, and modified the bid quantities for Power’s peaking units. Power has implemented procedures and continues to review its policies and practices to mitigate the risk of similar issues occurring in the future. During the three months ended March 31, 2014, based upon its best estimate available at the time, Power recorded a pre-tax charge to income in the amount of $25 million related to this matter.

Since September 2014, FERC Staff has been conducting a preliminary, non-public staff investigation into these matters. While considerable uncertainty remains as to the final resolution of these matters, based upon developments in the investigation in the first quarter of 2017, Power believes the disgorgement and interest costs related to the cost-based bidding matter may range between approximately $35 million and $135 million, depending on the legal interpretation of the principles under the PJM Tariff, plus penalties. Since no point within this range is more likely than any other, Power has accrued the low end of this range of $35 million by recording an additional pre-tax charge to income of $10 million during the three months ended March 31, 2017. Power is unable to reasonably estimate the range of possible loss, if any, for the quantity of energy offered matter or the penalties that FERC would impose relating to either the cost-based bidding or quantity of energy matter. However, any of these amounts could be individually material to PSEG and Power.

Power continues to believe that it has legal defenses that it may assert in a judicial challenge, including the legal defense that its cost-based bidding in a substantial majority of the hours was below the allowed rate under the Tariff and therefore any errors in those hours did not violate the Tariff or were immaterial. Furthermore, it is unclear whether the quantity of energy offered violated any legal requirement. As a result, PSEG and Power cannot predict the final outcome of these matters.

~~Financial Transmission Rights (FTR) Auction Matter~~

In January 2017, ER&T received requests from the FERC Office of Enforcement relating to the planning and implementation of ER&T’s participation in PJM’s annual FTR auction for the 2016-2017 planning year and the monthly PJM FTR auctions for February, March and April 2016. In October 2017, FERC Staff closed the investigation with no impact to PSEG’s operations or future earnings results.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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. However, Hudson Power has the right to challenge this determination. We are unable to predict the outcome of these proceedings.

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.

Newark Customer Incident

On the morning of July 5, 2018, PSE&G discontinued electricity to the home of a customer residing in Newark because of outstanding arrears on that customer’s account. Subsequent to the discontinuation of electricity, that customer died on the afternoon of July 5th. The family of the customer, who was on hospice care, raised allegations in the media regarding PSE&G’s conduct surrounding the discontinuation and restoration of electricity to the home of the customer, claiming that the discontinuation of electric service prevented the customer from using life sustaining medical equipment. The BPU initiated an investigation into the matter and that investigation is ongoing. In addition, PSE&G received a grand jury subpoena from the Essex County Prosecutor’s Office (ECPO) for records and correspondence between PSE&G and the customer. PSE&G is fully cooperating with the BPU and the ECPO in both proceedings. PSEG cannot predict the outcome of the pending proceedings regarding this incident at this time.

The PSEG Board of Directors (PSEG Board) retained outside counsel to conduct an independent investigation of the facts surrounding this incident with the full support and cooperation of management. The independent investigation concluded that the disconnection itself was not improper; however, it did identify issues related to PSE&G’s response once it was notified of the disconnection. The PSEG Board reviewed and considered the findings and conclusions of the investigation and PSE&G’s proposed corrective actions. PSE&G’s progress on implementation of the corrective actions will continue to be overseen by the PSEG Board.

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. Caithness has represented to the court that it will no longer pursue its antitrust claims and is considering whether to file its claim of intentional interference of prospective business relations 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 September 30, 2019.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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 has 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. 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 September 30, 2019.

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.

Note ~~10.~~12. Debt and Credit Facilities

Long-Term Debt Financing Transactions

The following long-term debt transactions occurred in the nine months ended September 30, ~~2017:~~2019:

PSEG


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

~~entered into an agreement for~~repaid a ~~new~~$350 million term loan ~~maturing June 2019. The term loan has a balance of $700 million at~~with an interest rate of 1 month LIBOR + 0.80% ~~and can be terminated at any time without penalty.~~.

PSE&G


•	issued $400 million of 3.20% Secured Medium-Term Notes, Series M, due August 2049,


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

issued ~~$425~~$375 million of ~~3.00%~~3.85% Secured Medium-Term Notes, Series LM, due May ~~2027.~~2049, and

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


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

PSEG Power

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

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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.

In March 2017, PSEG, Power and PSE&G amended their credit agreements, extending the expiration dates to March 2022. Concurrently, PSEG increased its existing $1 billion in credit facilities to $1.5 billion and Power decreased its existing $2.6 billion in credit facilities to $2.1 billion, which includes two new 3-year $100 million letter of credit facilities that expire in March 2020.

The commitments under the $4.2 billion credit facilities are provided by a diverse bank group. As of September 30, ~~2017,~~2019, the total available credit capacity was ~~$3.8~~$3.6 billion.

As of September 30, ~~2017,~~2019, no single institution represented more than 8%9% of the total commitments in the credit facilities.

As of September 30, ~~2017,~~2019, total credit capacity was in excess of the total anticipated maximum liquidity requirements ~~of PSEG, PSE&G and Power.~~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 its subsidiaries’ liquidity needs. The total credit facilities and available liquidity as of September 30, ~~2017~~2019 were as follows:

As of September 30, 2017
Company/Facility
Total
Facility
Usage
Available
Liquidity

Expiration
Date
Primary Purpose
Millions
PSEG
  5-year Credit Facilities (A) $ 1,500
$ 215
$ 1,285
Mar 2022 Commercial Paper Support/Funding/Letters of Credit
Total PSEG $ 1,500
$ 215
$ 1,285

PSE&G
5-year Credit Facility (A) $ 600
$ 15
$ 585
Mar 2022 Commercial Paper Support/Funding/Letters of Credit
Total PSE&G $ 600
$ 15
$ 585

Power
  3-year LC Facilities $ 200
$ 112
$ 88
Mar 2020 Letters of Credit
  5-year Credit Facilities 1,900
70
1,830
Mar 2022 Funding/Letters of Credit
Total Power $ 2,100
$ 182
$ 1,918

Total $ 4,200
$ 412
$ 3,788




	As of September 30, 2019
Company/Facility	Total Facility		Usage (D)		Available Liquidity		Expiration Date	Primary Purpose
	Millions
PSEG
5-year Credit Facilities (A)	$	1,500	$	349	$	1,151	Mar 2023	Commercial Paper Support/Funding/Letters of Credit
Total PSEG	$	1,500	$	349	$	1,151
PSE&G
5-year Credit Facility (B)	$	600	$	26	$	574	Mar 2023	Commercial Paper Support/Funding/Letters of Credit
Total PSE&G	$	600	$	26	$	574
PSEG Power
3-year Letter of Credit Facilities	$	200	$	136	$	64	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	$	176	$	1,924
Total	$	4,200	$	551	$	3,649


(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 September 30, ~~2017,~~2019, PSEG had ~~$202~~$336 million outstanding at a weighted average interest rate of ~~1.37%~~2.44%. PSE&G had ~~no amounts~~$10 million outstanding at a weighted average interest rate of 2.17% under its Commercial Paper Program as of September 30, ~~2017.~~2019.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Note ~~11.~~13. 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 normal purchases and normal sales (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 effective as cash flow or fair value hedges. PSEG Power ~~and PSE&G enter~~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 ~~primarily~~ 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 11. Commitments and Contingent Liabilities. Changes in the fair market value of ~~the~~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 September 30, ~~2017~~2019 or December 31, ~~2016. The fair value hedges reduced interest expense by $2 million and $6 million for the three months and nine months ended September 30, 2016.~~2018.

Cash Flow Hedges

PSEG uses interest rate swaps and other derivatives, which are designated and effective as cash flow hedges, to manage its exposure to the variability of cash flows, primarily related ~~primarily~~ to variable-rate debt instruments. As of September 30, ~~2017 and December 31, 2016,~~2019, PSEG had interest rate hedges outstanding totaling ~~$500~~$700 million. These hedges convert PSEG’s ~~$500~~$700 million ~~variable rate~~variable-rate term loan due November ~~2017~~2020 into a ~~fixed~~fixed-rate loan. PSEG interest rate ~~loan~~. Ashedges totaling $600 million were terminated during the second quarter and a loss of ~~December 31, 2016,~~$(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 12. Debt and Credit Facilities.

The fair value of these hedges was $1$(7) million ~~and was immaterial~~ as of September 30, ~~2017. There was~~2019 and there were no ~~ineffectiveness~~outstanding interest rate hedges as of ~~September 30, 2017 and~~ December 31, ~~2016.~~

2018. The Accumulated Other Comprehensive Income (Loss) (after tax) related to ~~existing~~outstanding and terminated interest rate derivatives designated as cash flow hedges was $1$(17) million and $2$(1) million as of September 30, ~~2017~~2019 and December 31, ~~2016,~~2018, respectively. The after-tax unrealized ~~gain~~losses on these hedges expected to be reclassified to earnings during the next 12 months ~~is immaterial.~~are $(2) million.

Fair Values of Derivative Instruments

The following are the fair values of derivative instruments on the Condensed 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 Condensed Consolidated Balance Sheets of PSEG Power and PSEG.

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(UNAUDITED)~~

For additional information see Note 14. Fair Value Measurements. The following tabular disclosure does not include the offsetting of trade receivables and payables.

As of September 30, 2017
Power (A) PSEG (A) Consolidated
Not Designated Designated as Hedges
Balance Sheet Location
Energy-
Related
Contracts

Netting
(B)

Total
Power

Interest
Rate
Swaps

Total
Derivatives

Millions
Derivative Contracts
Current Assets $ 352
$ (268 ) $ 84
$ —
$ 84

Noncurrent Assets 178
(116 ) 62
—
62

Total Mark-to-Market Derivative Assets $ 530
$ (384 ) $ 146
$ —
$ 146

Derivative Contracts
Current Liabilities $ (268 ) $ 261
$ (7 ) $ —
$ (7 )
Noncurrent Liabilities (110 ) 109
(1 ) —
(1 )
Total Mark-to-Market Derivative (Liabilities) $ (378 ) $ 370
$ (8 ) $ —
$ (8 )
Total Net Mark-to-Market Derivative Assets (Liabilities) $ 152
$ (14 ) $ 138
$ —
$ 138

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

As of December 31, 2016
Power (A) PSE&G (A) PSEG (A) Consolidated
Not Designated Not Designated Designated as Hedges
Balance Sheet Location
Energy-
Related
Contracts

Netting
(B)

Total
Power

Energy-
Related
Contracts

Interest
Rate
Swaps

Total
Derivatives

Millions
Derivative Contracts
Current Assets $ 435
$ (273 ) $ 162
$ —
$ 1
$ 163

Noncurrent Assets 122
(98 ) 24
—
—
24

Total Mark-to-Market Derivative Assets $ 557
$ (371 ) $ 186
$ —
$ 1
$ 187

Derivative Contracts
Current Liabilities $ (285 ) $ 277
$ (8 ) $ (5 ) $ —
$ (13 )
Noncurrent Liabilities (98 ) 95
(3 ) —
—
(3 )
Total Mark-to-Market Derivative (Liabilities) $ (383 ) $ 372
$ (11 ) $ (5 ) $ —
$ (16 )
Total Net Mark-to-Market Derivative Assets (Liabilities) $ 174
$ 1
$ 175
$ (5 ) $ 1
$ 171

(UNAUDITED)




	As of September 30, 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	$	361		$	(343	)	$	18		$	—		$	18
Noncurrent Assets	228			(201		)	27			—			27
Total Mark-to-Market Derivative Assets	$	589		$	(544	)	$	45		$	—		$	45
Derivative Contracts
Current Liabilities	$	(369	)	$	343		$	(26	)	$	(6	)	$	(32	)
Noncurrent Liabilities	(204		)	200			(4		)	(1		)	(5		)
Total Mark-to-Market Derivative (Liabilities)	$	(573	)	$	543		$	(30	)	$	(7	)	$	(37	)
Total Net Mark-to-Market Derivative Assets (Liabilities)	$	16		$	(1	)	$	15		$	(7	)	$	8




	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 September 30, ~~2017~~2019 and December 31, ~~2016. PSE&G does not have any derivative contracts subject to master netting or similar agreements.~~2018.

(B)

Represents the netting of fair value balances with the same counterparty (where the right of offset exists) and the application of collateral. All cash collateral received or posted that has been allocated to derivative positions, where the right of offset exists, has been offset on the Condensed Consolidated Balance Sheets. As of September 30, ~~2017,~~2019 and December 31, 2018, PSEG Power had net cash collateral/margin payments to counterparties of $92 million and $393 million, respectively. Of these net cash/collateral ~~(received) paid~~margin payments, $(1) million as of ~~$(14)~~September 30, 2019 and $153 million ~~was~~as December 31, 2018 were netted against the corresponding net derivative contract positions. The $(1) million as of September 30, 2019 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.

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(UNAUDITED)~~

~~Table~~Certain of ~~Contents~~

positions. Of the $(14) million as of September 30, 2017, $(7) million was netted against current assets, and $(7) million was netted against noncurrent assets. As of December 31, 2016, net cash collateral (received) paid of $1 million was netted against the corresponding net derivative contract positions. Of the $1 million as of December 31, 2016, $(3) million was netted against noncurrent assets, and $4 million was netted against current liabilities.

~~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

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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 ~~$16~~$35 million and ~~$19~~$22 million as of September 30, ~~2017~~2019 and December 31, ~~2016,~~2018, respectively. As of ~~each of~~ September 30, ~~2017~~2019 and December 31, ~~2016,~~2018, PSEG Power had the contractual right of offset of $9$6 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 $7$29 million and ~~$10~~$15 million as of September 30, ~~2017~~2019 and December 31, ~~2016,~~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 Condensed Consolidated Statements of Operations and on Accumulated Other Comprehensive Income (AOCI) of derivative instruments designated as cash flow hedges for the three months and nine months ended September 30, ~~2017~~2019 and ~~2016.~~

Derivatives in Cash Flow
Hedging Relationships

Amount of Pre-Tax
Gain (Loss)
Recognized in AOCI on Derivatives
(Effective Portion)

Location of
Pre-Tax Gain (Loss) Reclassified from AOCI into Income

Amount of Pre-Tax
Gain (Loss)
Reclassified from AOCI into Income
(Effective Portion)

Three Months Ended Three Months Ended
September 30, September 30,
2017 2016 2017 2016
Millions Millions
PSEG
Interest Rate Swaps $ 1
$ 1
Interest Expense $ 2
$ —

Total PSEG $ 1
$ 1
$ 2
$ —

2018:

Derivatives in Cash Flow
Hedging Relationships

Amount of Pre-Tax
Gain (Loss)
Recognized in AOCI on Derivatives
(Effective Portion)

Location of
Pre-Tax Gain (Loss) Reclassified from AOCI into Income

Amount of Pre-Tax
Gain (Loss)
Reclassified from AOCI into Income
(Effective Portion)

Nine Months Ended Nine Months Ended
September 30, September 30,
2017 2016 2017 2016
Millions Millions
PSEG
Interest Rate Swaps $ 1
$ 3
Interest Expense $ 2
$ —

Total PSEG $ 1
$ 3
$ 2
$ —




Derivatives in Cash Flow Hedging Relationships	Amount of Pre-Tax Gain (Loss) Recognized in AOCI on Derivatives				Location of Pre-Tax Gain (Loss) Reclassified from AOCI into Income	Amount of Pre-Tax Gain (Loss) Reclassified from AOCI into Income
	Three Months Ended					Three Months Ended
	September 30,					September 30,
	2019		2018			2019			2018
	Millions					Millions
PSEG
Interest Rate Swaps	$	—	$	—	Interest Expense	$	(1	)	$	—
Total PSEG	$	—	$	—		$	(1	)	$	—

~~There were no pre-tax gains (losses) recognized~~




Derivatives in Cash Flow Hedging Relationships	Amount of Pre-Tax Gain (Loss) Recognized in AOCI on Derivatives					Location of Pre-Tax Gain (Loss) Reclassified from AOCI into Income	Amount of Pre-Tax Gain (Loss) Reclassified from AOCI into Income
	Nine Months Ended						Nine Months Ended
	September 30,						September 30,
	2019			2018			2019			2018
	Millions						Millions
PSEG
Interest Rate Swaps	$	(24	)	$	—	Interest Expense	$	(2	)	$	—
Total PSEG	$	(24	)	$	—		$	(2	)	$	—

The effect of interest rate cash flow hedges is recorded in ~~income on derivatives (ineffective portion) as~~Interest Expense in PSEG’s Condensed Consolidated Statement of Operations. For the three months and nine months ended September 30, ~~2017 and~~

~~2016.~~

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(UNAUDITED)~~

~~Table~~2019, the amount of ~~Contents~~

gain or loss on interest rate hedges reclassified from Accumulated Other Comprehensive Income (Loss) into income was $(1) million after-tax. The amount of gain or loss on interest rate hedges reclassified from Accumulated Other Comprehensive Income (Loss) into income for 2018 was immaterial.

The following reconciles the ~~AOCI~~Accumulated Other Comprehensive Income (Loss) for derivative activity included in the Accumulated Other Comprehensive Loss of PSEG on a pre-tax and after-tax basis.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Accumulated Other Comprehensive Income Pre-Tax After-Tax
Millions
Balance as of December 31, 2015 $ —
$ —

Gain Recognized in AOCI 3
2

Less: Gain Reclassified into Income —
—

Balance as of December 31, 2016 $ 3
$ 2

Gain Recognized in AOCI 1
—

Less: Gain Reclassified into Income (2 ) (1 )
Balance as of September 30, 2017 $ 2
$ 1




Accumulated Other Comprehensive Income (Loss)	Pre-Tax			After-Tax
	Millions
Balance as of December 31, 2017	$	—		$	—
Loss Recognized in AOCI	(2		)	(1		)
Less: Loss Reclassified into Income	—			—
Balance as of December 31, 2018	$	(2	)	$	(1	)
Loss Recognized in AOCI	(24		)	(17		)
Less: Loss Reclassified into Income	2			1
Balance as of September 30, 2019	$	(24	)	$	(17	)

The following shows the effect on the Condensed Consolidated Statements of Operations of derivative instruments not designated as hedging instruments or as NPNS for the three months and nine months ended September 30, ~~2017~~2019 and ~~2016.~~2018, respectively. 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 ~~for which~~that PSEG Power has designated as NPNS, such as its BGS contracts and certain other energy supply contracts that it has with other utilities and companies with retail load.




Derivatives Not Designated as Hedges	Location of Pre-Tax Gain (Loss) Recognized in Income on Derivatives	Pre-Tax Gain (Loss) Recognized in Income on Derivatives
		Three Months Ended						Nine Months Ended
		September 30,						September 30,
		2019			2018			2019			2018
		Millions
PSEG and PSEG Power
Energy-Related Contracts	Operating Revenues	$	(76	)	$	(130	)	$	385		$	(154	)
Energy-Related Contracts	Energy Costs	(3		)	5			(77		)	12
Total PSEG and PSEG Power		$	(79	)	$	(125	)	$	308		$	(142	)

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
Three Months Ended Nine Months Ended
September 30, September 30,
2017 2016 2017 2016
Millions
PSEG and Power
Energy-Related Contracts Operating Revenues $ 25
$ 125
$ 221
$ 255

Energy-Related Contracts Energy Costs (3 ) (11 ) (19 ) (3 )
Total PSEG and Power $ 22
$ 114
$ 202
$ 252

The following ~~reflects~~table summarizes the ~~gross~~net notional volume ~~on an absolute value basis,~~purchases/(sales) of ~~derivatives~~open derivative transactions by commodity as of September 30, ~~2017~~2019 and December 31, ~~2016.~~2018.




Type	Notional	Total		PSEG	PSEG Power		PSE&G
		Millions
As of September 30, 2019
Natural Gas	Dekatherm (Dth)	405		—	405		—
Electricity	MWh	(61	)	—	(61	)	—
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		—

Type Notional Total PSEG Power PSE&G
Millions
As of September 30, 2017
Natural Gas Dekatherm (Dth) 265
—
265
—

Electricity MWh 332
—
332
—

Financial Transmission Rights (FTRs) MWh 5
—
5
—

Interest Rate Swaps U.S. Dollars 500
500
—
—

As of December 31, 2016
Natural Gas Dth 357
—
348
9

Electricity MWh 323
—
323
—

FTRs MWh 9
—
9
—

Interest Rate Swaps U.S. Dollars 500
500
—
—

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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.

As of September 30, 2017, 99% of the net credit exposure for Power’s 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).

The following table provides information on PSEG Power’s credit risk from ~~others,~~wholesale counterparties, net of collateral, as of September 30, ~~2017.~~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 September 30, 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).

Rating
Current
Exposure
Collateral Held
Net
Exposure

Number of
Counterparties
>10%

Net Exposure of
Counterparties
>10%

Millions Millions
Investment Grade $ 318
$ 55
$ 263
2
$ 128
(A)
Non-Investment Grade 5
1
4
—
—

Total $ 323
$ 56
$ 267
2
$ 128




Rating	Current Exposure		Securities held as Collateral		Net Exposure		Number of Counterparties >10%	Net Exposure of Counterparties >10%
	Millions							Millions
Investment Grade	$	226	$	22	$	204	2	$	100	(A)
Non-Investment Grade	2		—		2		—	—
Total	$	228	$	22	$	206	2	$	100


(A)	~~Includes~~ Represents net exposure of ~~$97~~$67 million with PSE~~&G.~~&G and $33 million with a non-affiliated counterparty.

As of September 30, ~~2017,~~2019, collateral held from counterparties where PSEG Power had credit exposure included $3 million in cash collateral and ~~$53~~$19 million in letters of credit.

As of September 30, ~~2017~~2019, PSEG Power had ~~144~~127 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 September 30, ~~2017,~~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 September 30, ~~2017,~~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.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Note ~~12.~~14. 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. ~~As of September 30, 2017, these consisted~~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 September 30, ~~2017~~2019 and December 31, ~~2016,~~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.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Recurring Fair Value Measurements as of September 30, 2017
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) $ 220
$ —
$ 220
$ —
$ —

Derivative Contracts:
Energy-Related Contracts (B) $ 146
$ (384 ) $ 11
$ 513
$ 6

NDT Fund (D)
Equity Securities $ 1,032
$ —
$ 1,030
$ 2
$ —

Debt Securities—U.S. Treasury $ 249
$ —
$ —
$ 249
$ —

Debt Securities—Govt Other $ 318
$ —
$ —
$ 318
$ —

Debt Securities—Corporate $ 358
$ —
$ —
$ 358
$ —

Other Securities $ 55
$ —
$ 55
$ —
$ —

Rabbi Trust (D)
Equity Securities—Mutual Funds $ 23
$ —
$ 23
$ —
$ —

Debt Securities—U.S. Treasury $ 51
$ —
$ —
$ 51
$ —

Debt Securities—Govt Other $ 33
$ —
$ —
$ 33
$ —

Debt Securities—Corporate $ 120
$ —
$ —
$ 120
$ —

Other Securities $ 2
$ —
$ 2
$ —
$ —

Liabilities:
Derivative Contracts:
Energy-Related Contracts (B) $ (8 ) $ 370
$ (6 ) $ (372 ) $ —

PSE&G
Assets:
Cash Equivalents (A) $ 220
$ —
$ 220
$ —
$ —

Rabbi Trust (D)
Equity Securities—Mutual Funds $ 5
$ —
$ 5
$ —
$ —

Debt Securities—U.S. Treasury $ 10
$ —
$ —
$ 10
$ —

Debt Securities—Govt Other $ 7
$ —
$ —
$ 7
$ —

Debt Securities—Corporate $ 24
$ —
$ —
$ 24
$ —

Other Securities $ —
$ —
$ —
$ —
$ —

Power

Assets:
Derivative Contracts:
Energy-Related Contracts (B) $ 146
$ (384 ) $ 11
$ 513
$ 6

NDT Fund (D)
Equity Securities $ 1,032
$ —
$ 1,030
$ 2
$ —

Debt Securities—U.S. Treasury $ 249
$ —
$ —
$ 249
$ —

Debt Securities—Govt Other $ 318
$ —
$ —
$ 318
$ —

Debt Securities—Corporate $ 358
$ —
$ —
$ 358
$ —

Other Securities $ 55
$ —
$ 55
$ —
$ —

Rabbi Trust (D)
Equity Securities—Mutual Funds $ 6
$ —
$ 6
$ —
$ —

Debt Securities—U.S. Treasury $ 13
$ —
$ —
$ 13
$ —

Debt Securities—Govt Other $ 8
$ —
$ —
$ 8
$ —

Debt Securities—Corporate $ 30
$ —
$ —
$ 30
$ —

Other Securities $ —
$ —
$ —
$ —
$ —

Liabilities:
Derivative Contracts:
Energy-Related Contracts (B) $ (8 ) $ 370
$ (6 ) $ (372 ) $ —




	Recurring Fair Value Measurements as of September 30, 2019
Description	Total			Netting (D)			Quoted Market Prices for Identical Assets (Level 1)			Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
	Millions
PSEG
Assets:
Derivative Contracts:
Energy-Related Contracts (A)	$	45		$	(544	)	$	10		$	576		$	3
NDT Fund (B)
Equity Securities	$	1,072		$	—		$	1,071		$	1		$	—
Debt Securities—U.S. Treasury	$	219		$	—		$	—		$	219		$	—
Debt Securities—Govt Other	$	347		$	—		$	—		$	347		$	—
Debt Securities—Corporate	$	496		$	—		$	—		$	496		$	—
Rabbi Trust (B)
Equity Securities	$	25		$	—		$	25		$	—		$	—
Debt Securities—U.S. Treasury	$	68		$	—		$	—		$	68		$	—
Debt Securities—Govt Other	$	41		$	—		$	—		$	41		$	—
Debt Securities—Corporate	$	112		$	—		$	—		$	112		$	—
Liabilities:
Derivative Contracts:
Energy-Related Contracts (A)	$	(30	)	$	543		$	(37	)	$	(534	)	$	(2	)
Interest Rate Swaps (C)	$	(7	)	$	—		$	—		$	(7	)	$	—
PSE&G
Assets:
Rabbi Trust (B)
Equity Securities	$	5		$	—		$	5		$	—		$	—
Debt Securities—U.S. Treasury	$	13		$	—		$	—		$	13		$	—
Debt Securities—Govt Other	$	8		$	—		$	—		$	8		$	—
Debt Securities—Corporate	$	22		$	—		$	—		$	22		$	—
PSEG Power
Assets:
Derivative Contracts:
Energy-Related Contracts (A)	$	45		$	(544	)	$	10		$	576		$	3
NDT Fund (B)
Equity Securities	$	1,072		$	—		$	1,071		$	1		$	—
Debt Securities—U.S. Treasury	$	219		$	—		$	—		$	219		$	—
Debt Securities—Govt Other	$	347		$	—		$	—		$	347		$	—
Debt Securities—Corporate	$	496		$	—		$	—		$	496		$	—
Rabbi Trust (B)
Equity Securities	$	7		$	—		$	7		$	—		$	—
Debt Securities—U.S. Treasury	$	17		$	—		$	—		$	17		$	—
Debt Securities—Govt Other	$	10		$	—		$	—		$	10		$	—
Debt Securities—Corporate	$	28		$	—		$	—		$	28		$	—
Liabilities:
Derivative Contracts:
Energy-Related Contracts (A)	$	(30	)	$	543		$	(37	)	$	(534	)	$	(2	)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)




	Recurring Fair Value Measurements as of December 31, 2018
Description	Total			Netting (D)			Quoted Market Prices for Identical Assets (Level 1)			Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
	Millions
PSEG
Assets:
Cash Equivalents (E)	$	100		$	—		$	100		$	—		$	—
Derivative Contracts:
Energy-Related Contracts (A)	$	12		$	(551	)	$	29		$	527		$	7
NDT Fund (B)
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 (B)
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 (A)	$	(15	)	$	704		$	(36	)	$	(677	)	$	(6	)
PSE&G
Assets:
Rabbi Trust (B)
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 (A)	$	12		$	(551	)	$	29		$	527		$	7
NDT Fund (B)
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 (B)
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 (A)	$	(15	)	$	704		$	(36	)	$	(677	)	$	(6	)

Recurring Fair Value Measurements as of December 31, 2016
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) $ 365
$ —
$ 365
$ —
$ —

Derivative Contracts:
Energy-Related Contracts (B) $ 186
$ (371 ) $ 17
$ 533
$ 7

Interest Rate Swaps (C) $ 1
$ —
$ —
$ 1
$ —

NDT Fund (D)
Equity Securities $ 957
$ —
$ 954
$ 3
$ —

Debt Securities—U.S. Treasury $ 227
$ —
$ —
$ 227
$ —

Debt Securities—Govt Other $ 293
$ —
$ —
$ 293
$ —

Debt Securities—Corporate $ 337
$ —
$ —
$ 337
$ —

Other Securities $ 44
$ —
$ 44
$ —
$ —

Rabbi Trust (D)
Equity Securities—Mutual Funds $ 22
$ —
$ 22
$ —
$ —

Debt Securities—U.S. Treasury $ 37
$ —
$ —
$ 37
$ —

Debt Securities—Govt Other $ 66
$ —
$ —
$ 66
$ —

Debt Securities—Corporate $ 91
$ —
$ —
$ 91
$ —

Other Securities $ 1
$ —
$ 1
$ —
$ —

Liabilities:
Derivative Contracts:
Energy-Related Contracts (B) $ (16 ) $ 372
$ (18 ) $ (364 ) $ (6 )
PSE&G
Assets:
Cash Equivalents (A) $ 365
$ —
$ 365
$ —
$ —

Derivative Contracts:
Energy Related Contracts (B) $ —
$ —
$ —
$ —
$ —

Rabbi Trust (D)
Equity Securities—Mutual Funds $ 5
$ —
$ 5
$ —
$ —

Debt Securities—U.S. Treasury $ 7
$ —
$ —
$ 7
$ —

Debt Securities—Govt Other $ 13
$ —
$ —
$ 13
$ —

Debt Securities—Corporate $ 18
$ —
$ —
$ 18
$ —

Other Securities $ —
$ —
$ —
$ —
$ —

Liabilities:
Derivative Contracts:
Energy-Related Contracts (B) $ (5 ) $ —
$ —
$ —
$ (5 )
Power
Assets:
Derivative Contracts:
Energy-Related Contracts (B) $ 186
$ (371 ) $ 17
$ 533
$ 7

NDT Fund (D)
Equity Securities $ 957
$ —
$ 954
$ 3
$ —

Debt Securities—U.S. Treasury $ 227
$ —
$ —
$ 227
$ —

Debt Securities—Govt Other $ 293
$ —
$ —
$ 293
$ —

Debt Securities—Corporate $ 337
$ —
$ —
$ 337
$ —

Other Securities $ 44
$ —
$ 44
$ —
$ —

Rabbi Trust (D)
Equity Securities—Mutual Funds $ 5
$ —
$ 5
$ —
$ —

Debt Securities—U.S. Treasury $ 9
$ —
$ —
$ 9
$ —

Debt Securities—Govt Other $ 16
$ —
$ —
$ 16
$ —

Debt Securities—Corporate $ 23
$ —
$ —
$ 23
$ —

Other Securities $ —
$ —
$ —
$ —
$ —

Liabilities:
Derivative Contracts:
Energy-Related Contracts (B) $ (11 ) $ 372
$ (18 ) $ (364 ) $ (1 )

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(UNAUDITED)~~


(A)	~~Represents money market mutual funds.~~


~~(B)~~	Level 1— ~~During 2016 a net fair value of $1 million relating to energy-related contracts was transferred from Level 2 into Level 1.~~ These contracts represent natural gas futures contracts executed on NYMEX, and are being valued solely on settled pricing inputs which come directly from the exchange.

Level 2—Fair values for energy-related contracts are obtained primarily using a market-based approach. Most derivative contracts (forward purchase or sale contracts and swaps) are valued using settled prices from similar assets and liabilities from an exchange, such as NYMEX, ICE and Nodal Exchange, or auction prices. Prices used in the valuation process are also corroborated independently by management to determine that values are based on actual transaction data or, in the absence of transactions, bid and offers for the day. Examples may include certain exchange and non-exchange traded capacity and electricity contracts and natural gas physical or swap contracts

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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)~~(B)	~~Interest rate swaps are valued using quoted prices on commonly quoted intervals, which are interpolated for periods different than~~As of September 30, 2019, 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.~~

~~(D)~~

~~The~~ fair value measurement ~~tables exclude an immaterial amount~~table excludes foreign currency of ~~cash as of September 30, 2017 and~~ $1 ~~million as of December 31, 2016, which is part of the NDT Fund.~~million. The NDT Fund maintains investments in various equity and fixed income ~~securities classified as “available for sale.”~~securities. The Rabbi Trust maintains investments in a Russell 3000 index fund and various fixed income securities classified as “available for sale” as of September 30, 2017. The Rabbi Trust maintained investments in a S&P 500 index fund and various securities classified as “available for sale” as of December 31, 2016.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 ~~open-ended mutual~~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 ~~mainly~~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, ~~investments are valued based on unadjusted quoted prices in active markets.~~dollar-denominated debt securities and government securities. The funds’ net asset value is priced and published daily. The Rabbi ~~Trust equity~~Trust’s Russell 3000 index fund is valued based on quoted prices in an active ~~market.~~market and can be redeemed daily without restriction.

Level 2—NDT and Rabbi Trust fixed income securities include ~~primarily~~ investment grade corporate bonds, collateralized mortgage obligations, ~~asset backed~~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.


~~(E)~~(C)	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.

(D)

Represents the netting of fair value balances with the same counterparty (where the right of offset exists) and the application of collateral. All cash collateral received or posted that has been allocated to derivative positions, where the right of offset exists, has been offset in the Condensed Consolidated Balance Sheets. As of September 30, 2017, net cash collateral (received) paid of $(14) million was netted against the corresponding net derivative contract positions. The $(14) million of cash collateral as of September 30, 2017 was netted against assets. As of December 31, 2016, net cash collateral (received) paid of $1 million was netted against the corresponding net derivative contract positions. Of the $1 million of cash collateral as of December 31, 2016, $(3) million was netted against assets, and $4 million was netted against liabilities.See Note 13. Financial Risk Management Activities for additional detail.


(E)	Represents money market mutual funds.

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

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(UNAUDITED)~~

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 ~~of Directors~~ 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.

For PSE&G, the natural gas supply contract was measured at fair value using modeling techniques taking into account the current price of natural gas adjusted for appropriate risk factors, as applicable, and internal assumptions about transportation costs, and accordingly, the fair value measurements are classified in Level 3. 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

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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 September 30, ~~2017~~2019 and December 31, ~~2016.~~2018.

Quantitative Information About Level 3 Fair Value Measurements

Significant
Fair Value as of Valuation Unobservable
Commodity Level 3 Position September 30, 2017 Technique(s) Input Range
Assets (Liabilities)
Millions
Power
Electricity Electric Load Contracts $ 5
$ —
Discounted Cash flow Historic Load Variability 0% to +10%
Gas Other 1
—

Total Power $ 6
$ —

Total PSEG $ 6
$ —




		Quantitative Information About Level 3 Fair Value Measurements

									Significant
			Fair Value as of					Valuation	Unobservable
	Commodity	Level 3 Position	September 30, 2019					Technique(s)	Input	Range
			Assets		(Liabilities)
			Millions
	PSEG Power
	Electricity	Electric Load Contracts	$	3	$	(1	)	Discounted Cash flow	Historic Load Variability	0% to 10%
	Gas	Gas Physical Contracts	—		—			Discounted Cash flow	Average Historical Basis	-40% to 0%
��	Electricity	Electric Options	$	—	$	(1	)	Discounted Cash flow	Implied Volatilities	45% to 190%
	Total PSEG Power		$	3	$	(2	)
	Total PSEG		$	3	$	(2	)




	Quantitative Information About Level 3 Fair Value Measurements

								Significant
		Fair Value as of					Valuation	Unobservable
Commodity	Level 3 Position	December 31, 2018					Technique(s)	Input	Range
		Assets		(Liabilities)
		Millions
PSEG Power
Electricity	Electric Load Contracts	$	2	$	(5	)	Discounted Cash flow	Historic Load Variability	0% to 15%
Gas	Gas Physical Contracts	5		(1		)	Discounted Cash flow	Average Historical Basis	-40% to 0%
Total PSEG Power		$	7	$	(6	)
Total PSEG		$	7	$	(6	)

Quantitative Information About Level 3 Fair Value Measurements

Significant
Fair Value as of Valuation Unobservable
Commodity Level 3 Position December 31, 2016 Technique(s) Input Range
Assets (Liabilities)
Millions
PSE&G
Gas Natural Gas Supply Contract $ —
$ (5 ) Discounted Cash Flow Transportation Costs $0.60 to $0.80/Dth
Total PSE&G $ —
$ (5 )
Power
Electricity Electric Load Contracts $ 7
$ (1 ) Discounted Cash Flow Historic Load Variability 0% to +10%
Gas (A) Other —
—

Total Power $ 7
$ (1 )
Total PSEG $ 7
$ (6 )


~~(A)~~	~~Includes gas positions which were immaterial.~~

Significant unobservable inputs listed above would have a direct impact on the fair values of the above Level 3 instruments if they were adjusted. For energy-related contracts in cases where PSEG Power is a seller, an increase in the load variability would decrease the fair value. For gas-related contracts in cases where PSEG Power is a buyer, an increase in the average historical basis would increase the fair value.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

A reconciliation of the beginning and ending balances of Level 3 derivative contracts and securities for the three months and nine months ended September 30, ~~2017~~2019 and September 30, ~~2016,~~2018, respectively, follows:

~~Changes in Level 3 Assets and (Liabilities) Measured at Fair Value on a Recurring Basis for the Three Months and Nine Months Ended September 30, 2017~~

Three Months Ended September 30, 2017

Total Gains or (Losses)
Realized/Unrealized

Description Balance as of July 1, 2017
Included in
Income (A)

Included in
Regulatory Assets/
Liabilities (B)

Purchases
(Sales)

Issuances/
Settlements
(C)

Transfers
In/Out (D)
Balance as of September 30, 2017
Millions
PSEG
Net Derivative Assets (Liabilities) $ 6
$ 3
$ —
$ —
$ (3 ) $ —
$ 6

PSE&G
Net Derivative Assets (Liabilities) $ —
$ —
$ —
$ —
$ —
$ —
$ —

Power
Net Derivative Assets (Liabilities) $ 6
$ 3
$ —
$ —
$ (3 ) $ —
$ 6

Nine Months Ended September 30, 2017

Total Gains or (Losses)
Realized/Unrealized

Description Balance as of January 1, 2017
Included in
Income (A)

Included in
Regulatory Assets/
Liabilities (B)

Purchases
(Sales)

Issuances/
Settlements
(C)

Transfers
In/Out (D)
Balance as of September 30, 2017
Millions
PSEG
Net Derivative Assets (Liabilities) $ 1
$ 29
$ 5
$ —
$ (28 ) $ (1 ) $ 6

PSE&G
Net Derivative Assets (Liabilities) $ (5 ) $ —
$ 5
$ —
$ —
$ —
$ —

Power
Net Derivative Assets (Liabilities) $ 6
$ 29
$ —
$ —
$ (28 ) $ (1 ) $ 6

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(UNAUDITED)~~

Changes in Level 3 Assets and (Liabilities) Measured at Fair Value on a Recurring Basis

for the Three MonthsandNine Months Ended September 30, ~~2016~~2019

Three Months Ended September 30, 2016

Total Gains or (Losses)
Realized/Unrealized

Description Balance as of July 1, 2016
Included in
Income (E)

Included in
Regulatory Assets/
Liabilities (B)

Purchases
(Sales)

Issuances/
Settlements
(C)

Transfers
In/Out
(D)
Balance as of September 30, 2016
Millions
PSEG
Net Derivative Assets (Liabilities) $ 5
$ 8
$ (2 ) $ 4
$ (4 ) $ —
$ 11

PSE&G
Net Derivative Assets (Liabilities) $ (2 ) $ —
$ (2 ) $ —
$ —
$ —
$ (4 )
Power
Net Derivative Assets (Liabilities) $ 7
$ 8
$ —
$ 4
$ (4 ) $ —
$ 15

Nine Months Ended September 30, 2016

Total Gains or (Losses)
Realized/Unrealized

Description Balance as of January 1, 2016
Included in
Income (E)

Included in
Regulatory Assets/
Liabilities (B)

Purchases
(Sales)

Issuances/
Settlements
(C)

Transfers
In/Out (D)
Balance as of September 30, 2016

PSEG
Net Derivative Assets (Liabilities) $ 13
$ 24
$ (6 ) $ 4
$ (24 ) $ —
$ 11

PSE&G
Net Derivative Assets (Liabilities) $ 2
$ —
$ (6 ) $ —
$ —
$ —
$ (4 )
Power
Net Derivative Assets (Liabilities) $ 11
$ 24
$ —
$ 4
$ (24 ) $ —
$ 15




	Three Months Ended September 30, 2019
Description	Balance as of June 30, 2019		Total Gains or (Losses) Realized/Unrealized Included in Income (A)		Purchases (Sales)		Issuances/ Settlements (B)			Transfers In/Out (C)		Balance as of September 30, 2019
	Millions
PSEG and PSEG Power
Net Derivative Assets (Liabilities)	$	4	$	1	$	—	$	(4	)	$	—	$	1

	Nine Months Ended September 30, 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 September 30, 2019
	Millions
PSEG and PSEG Power
Net Derivative Assets (Liabilities)	$	1	$	10	$	—	$	(10	)	$	—	$	1

Changes in Level 3 Assets and (Liabilities) Measured at Fair Value on a Recurring Basis

for the Three Months and Nine Months Ended September 30, 2018




	Three Months Ended September 30, 2018
Description	Balance as of June 30, 2018		Total Gains or (Losses) Realized/Unrealized Included in Income (A)			Purchases (Sales)		Issuances/ Settlements (B)			Transfers In/Out (C)		Balance as of September 30, 2018
	Millions
PSEG and PSEG Power
Net Derivative Assets (Liabilities)	$	4	$	(4	)	$	—	$	(1	)	$	—	$	(1	)

	Nine Months Ended September 30, 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 September 30, 2018
	Millions
PSEG and PSEG Power
Net Derivative Assets (Liabilities)	$	7	$	(8	)	$	—	$	—		$	—	$	(1	)

(A)

~~PSEG’s and Power’s~~Unrealized gains ~~and losses attributable to changes~~(losses) in ~~net~~the following table represent the change in derivative assets and liabilities ~~include $3 million and $29 million in Operating Income for the three months and nine months ended~~still held as of September 30, ~~2017, respectively. The $3 million in Operating Income is realized. Of the $29 million in Operating Income, $1 million is unrealized.~~


~~(B)~~	~~Mainly includes gains/losses on PSE&G’s derivative contracts that are not included in either earnings or Accumulated Other Comprehensive Income, as they are deferred as a Regulatory Asset/Liability~~2019 and ~~are expected to be recovered from/returned to PSE&G’s customers.~~


~~(C)~~	Represents $(3) million and $(28) million in settlements for the three months and nine months ended September 30, 2017, respectively. Represents $(4) million and $(24) million in settlements for the three months and nine months 2018.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

~~ended September 30, 2016, respectively.~~.




	Three Months Ended September 30,												Nine Months Ended September 30,
	2019						2018						2019						2018
	Total Gains (Losses)			Unrealized Gains (Losses)			Total Gains (Losses)			Unrealized Gains (Losses)			Total Gains (Losses)			Unrealized Gains (Losses)			Total Gains (Losses)			Unrealized Gains (Losses)
	Millions
PSEG and PSEG Power
Operating Revenues	$	(2	)	$	(4	)	$	(8	)	$	(8	)	$	14		$	5		$	(7	)	$	(7	)
Energy Costs	4			2			4			5			(4		)	(4		)	(1		)	(1		)
Total	$	2		$	(2	)	$	(4	)	$	(3	)	$	10		$	1		$	(8	)	$	(8	)


~~(D)~~(B)	~~During the three months ended September 30, 2017 there were no transfers in to or out~~ Includes settlements of Level 3. During the nine months ended September 30, 2017, $(1) million of net derivatives assets/liabilities were transferred from Level 2 to Level 3. There were no transfers in to or out of Level 3 during three months and nine months ended September 30, 2016.

~~(E)~~

~~PSEG’s and Power’s gains and losses attributable to changes in net derivative assets and liabilities include $8~~$(3) million and ~~$24~~$(9) million ~~in Operating Income~~ for the three months and nine months ended September 30, ~~2016, respectively. Of~~2019 and $(1) million for the ~~$8 million in Operating Income, $4 million is unrealized. The $24 million in Operating Income is realized.~~three months ended September 30, 2018.


(C)	There were no transfers into or out of Level 3 during the three months and nine months ended September 30, 2019 and 2018.

As of September 30, ~~2017,~~2019, PSEG carried ~~$2.6~~$2.4 billion of net assets that are measured at fair value on a recurring basis, of which $6$1 million of net assets was measured using unobservable inputs and classified as Level 3 within the fair value hierarchy.

As of September 30, 2018, PSEG carried $2.3 billion of net assets that are measured at fair value on a recurring basis, of which $1 million of net liabilities were measured using unobservable inputs and classified as Level 3 within the fair value hierarchy.

~~As of~~ ~~September 30, 2016~~, PSEG carried $2.6 billion of net assets that are measured at fair value on a recurring basis, of which $11 million of net assets were measured using unobservable inputs and classified as Level 3 within the fair value hierarchy.

Fair Value of Debt

The estimated fair values were determined using the market quotations or values of instruments with similar terms, credit ratings, remaining maturities and redemptions as of September 30, ~~2017~~2019 and December 31, ~~2016~~.

2018.

As of As of
September 30, 2017 December 31, 2016

Carrying
Amount

Fair
Value

Carrying
Amount

Fair
Value

Millions
Long-Term Debt:
PSEG (Parent) (A) (B) $ 1,896
$ 1,891
$ 1,195
$ 1,185

PSE&G (B) 8,243
8,857
7,818
8,240

Power - Recourse Debt (B) 2,385
2,657
2,382
2,578

Total Long-Term Debt $ 12,524
$ 13,405
$ 11,395
$ 12,003




	As of				As of
	September 30, 2019				December 31, 2018
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	Millions
Long-Term Debt:
PSEG (A) (B)	$	2,839	$	2,879	$	2,443	$	2,397
PSE&G (B)	9,826		11,253		9,184		9,374
PSEG Power (B)	2,839		3,162		2,835		2,996
Total Long-Term Debt	$	15,504	$	17,294	$	14,462	$	14,767

(A)

As of September 30, ~~2017, fair value~~2019 and December 31, 2018, includes afloating-rate term loans of $700 million ~~floating rate term loan in addition to the $500~~and $1,050 million, ~~floating rate term loan and net offsets as of December 31, 2016.~~respectively. The fair values of the term loan debt (Level 2 measurement) approximate the carrying ~~values~~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 ~~is obtained~~ (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.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Note ~~13.~~15. Other Income ~~and Deductions~~(Deductions)




	PSE&G		PSEG Power			Other (A)			Consolidated
	Millions
Three Months Ended September 30, 2019
NDT Fund Interest and Dividends	$	—	$	14		$	—		$	14
Allowance for Funds Used During Construction	14		—			—			14
Solar Loan Interest	4		—			—			4
Other	4		1			(2		)	3
Total Other Income (Deductions)	$	22	$	15		$	(2	)	$	35
Nine Months Ended September 30, 2019
NDT Fund Interest and Dividends	$	—	$	44		$	—		$	44
Allowance for Funds Used During Construction	41		—			—			41
Solar Loan Interest	12		—			—			12
Other	7		(1		)	(2		)	4
Total Other Income (Deductions)	$	60	$	43		$	(2	)	$	101
Three Months Ended September 30, 2018
NDT Fund Interest and Dividends	$	—	$	13		$	—		$	13
Allowance for Funds Used During Construction	13		—			—			13
Solar Loan Interest	5		—			—			5
Other	3		1			(2		)	2
Total Other Income (Deductions)	$	21	$	14		$	(2	)	$	33
Nine Months Ended September 30, 2018
NDT Fund Interest and Dividends	$	—	$	40		$	—		$	40
Allowance for Funds Used During Construction	40		—			—			40
Solar Loan Interest	14		—			—			14
Other	7		(2		)	—			5
Total Other Income (Deductions)	$	61	$	38		$	—		$	99

Other Income PSE&G Power Other (A) Consolidated
Millions
Three Months Ended September 30, 2017
NDT Fund Gains, Interest, Dividend and Other Income $ —
$ 41
$ —
$ 41

Allowance for Funds Used During Construction 14
—
—
14

Rabbi Trust Realized Gains, Interest and Dividends 1
1
—
2

Solar Loan Interest 6
—
—
6

Other 2
1
—
3

Total Other Income $ 23
$ 43
$ —
$ 66

Nine Months Ended September 30, 2017
NDT Fund Gains, Interest, Dividend and Other Income $ —
$ 117
$ —
$ 117

Allowance for Funds Used During Construction 42
—
—
42

Rabbi Trust Realized Gains, Interest and Dividends 5
6
11
22

Solar Loan Interest 16
—
—
16

Other 7
4
—
11

Total Other Income $ 70
$ 127
$ 11
$ 208

Three Months Ended September 30, 2016
NDT Fund Gains, Interest, Dividend and Other Income $ —
$ 21
$ —
$ 21

Allowance for Funds Used During Construction 14
—
—
14

Rabbi Trust Realized Gains, Interest and Dividends 1
—
3
4

Solar Loan Interest 6
—
—
6

Other 1
2
(1 ) 2

Total Other Income $ 22
$ 23
$ 2
$ 47

Nine Months Ended September 30, 2016
NDT Fund Gains, Interest, Dividend and Other Income $ —
$ 69
$ —
$ 69

Allowance for Funds Used During Construction 35
—
—
35

Rabbi Trust Realized Gains, Interest and Dividends 2
2
6
10

Solar Loan Interest 17
—
—
17

Other 7
3
(2 ) 8

Total Other Income $ 61
$ 74
$ 4
$ 139

Other Deductions PSE&G Power Other (A) Consolidated
Millions
Three Months Ended September 30, 2017
  NDT Fund Realized Losses and Expenses $ —
$ 8
$ —
$ 8

  Other 1
—
1
2

    Total Other Deductions $ 1
$ 8
$ 1
$ 10

Nine Months Ended September 30, 2017
  NDT Fund Realized Losses and Expenses $ —
$ 21
$ —
$ 21

  Other 3
1
5
9

    Total Other Deductions $ 3
$ 22
$ 5
$ 30

Three Months Ended September 30, 2016
  NDT Fund Realized Losses and Expenses $ —
$ 5
$ —
$ 5

  Other 1
1
1
3

  Total Other Deductions $ 1
$ 6
$ 1
$ 8

Nine Months Ended September 30, 2016
  NDT Fund Realized Losses and Expenses $ —
$ 31
$ —
$ 31

  Other 3
2
3
8

  Total Other Deductions $ 3
$ 33
$ 3
$ 39


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

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(UNAUDITED)~~

Note ~~14.~~16. Income Taxes

PSEG’s, PSE&G’s and PSEG Power’s effective tax rates for the three months and nine months ended September 30, ~~2017~~2019 and ~~2016~~2018 were as follows:




	Three Months Ended		Nine Months Ended
	September 30,		September 30,
	2019	2018	2019	2018
PSEG	6.9%	22.1%	11.2%	25.1%
PSE&G	6.5%	25.5%	6.1%	26.1%
PSEG Power	20.9%	16.7%	29.1%	24.1%

Three Months Ended Nine Months Ended
September 30, September 30,
2017 2016 2017 2016
PSEG 38.9% 36.5% 35.5% 36.3%
PSE&G 38.8% 36.1% 37.4% 36.1%
Power 41.9% 39.3% 37.9% 39.4%

For the three months and nine months ended September 30, ~~2017,~~2019, the differences in PSEG’s ~~effective tax rates as compared to the same periods in the prior year, as well as to the statutory tax rate of 40.85%, were due primarily to changes in uncertain tax positions~~ and ~~the NDT Fund. For the nine months ended September 30, 2017, the effective tax rate was also favorably impacted by interest from a New Jersey State income tax refund.~~

~~For the three months and nine months ended September 30, 2017, the differences in~~ PSE&G’s effective tax rates as compared to the same periods in the prior year ~~as well as to~~and the statutory tax rate of ~~40.85%,~~28.11% were due primarily to ~~changes in uncertain~~the flowback of PSE&G’s excess deferred income tax ~~positions, plant~~liabilities as a result of the Tax Act and ~~other flow-through items.~~tax repair-related accumulated deferred income taxes as a result of PSE&G’s 2018 settled distribution base rate case and the FERC- approved Section 205 filing, where applicable.

For the three months and nine months ended September 30, ~~2017,~~2019, the differences in PSEG Power’s effective tax rates as compared to the same periods in the prior year ~~as well as to the statutory tax rate of 40.85%,~~ were due primarily to ~~changes in~~the benefits associated with the remeasurement of uncertain tax positions ~~manufacturing deduction~~and associated interest in connection with the nuclear carryback claim and the ~~NDT Fund.~~

~~PSEG’s federal tax returns for the years~~ 2011 and 2012 ~~are currently being audited by the IRS. The~~federal income tax audit and other related claims are reasonably expected to be completed within the next 12 months. As a result, it is reasonably possible that a decrease in PSEG’s total unrecognized tax benefits may be necessaryrecorded in the ~~range~~third quarter of ~~$80 million to $180 million based on current estimates.~~

The Protecting Americans from Tax Hikes Act of 2015 (Tax Act) extended the 50% bonus depreciation rules for qualified property placed in service from January 1, 2015 through December 31, 2017. The rate is reduced to 40% and 30% for eligible property placed in service in 2018 and 2019, respectively. On May 8, 2017 the IRS issued guidance allowing for 50% bonus depreciation on long production property that is placed in service in 2018. For ~~long production property placed~~the three months ended September 30, 2019, the difference in service in 2019, qualified costs incurred before January 1, 2019 is afforded a 40% rate, while qualified costs incurred during 2019 receives a 30% rate. For long production property placed in service in 2020, subject to a written binding contract entered into before 2020, a 30% rate is allowed for qualified costs incurred before January 1, 2020, with a 0% rate thereafter. The Tax Act also extended the 30% ITC for qualified property placed in service starting January 1, 2016 through December 31, 2019 but reduces the ITC rate to 26% and 22% for projects commenced in 2020 and 2021, respectively. The financial impact of the extensions of the ITC rate will depend upon future transactions.

~~This provision has generated significant cash tax benefits for~~ PSEG PSE&G and Power through tax benefits related to the accelerated depreciation. These tax benefits would have otherwise been received over an estimated average 20 year period. However, these tax benefits will have a negative impact on the rate base of several of PSE&G’s programs.

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(UNAUDITED)~~

~~Note 15. Accumulated Other Comprehensive Income (Loss), Net of Tax~~

PSEG Other Comprehensive Income (Loss)
Three Months Ended September 30, 2017
Accumulated Other Comprehensive Income (Loss) Cash Flow Hedges Pension and OPEB Plans Available-for-Sale Securities Total
Millions
Balance as of June 30, 2017 $ 2
$ (386 ) $ 158
$ (226 )
Other Comprehensive Income before Reclassifications —
—
25
25

Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) (1 ) 6
(8 ) (3 )
Net Current Period Other Comprehensive Income (Loss) (1 ) 6
17
22

Balance as of September 30, 2017 $ 1
$ (380 ) $ 175
$ (204 )

PSEG Other Comprehensive Income (Loss)
Three Months Ended September 30, 2016
Accumulated Other Comprehensive Income (Loss) Cash Flow Hedges Pension and OPEB Plans Available-for-Sale Securities Total
Millions
Balance as of June 30, 2016 $ 1
$ (370 ) $ 117
$ (252 )
Other Comprehensive Income before Reclassifications 1
—
26
27

Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) —
9
(2 ) 7

Net Current Period Other Comprehensive Income (Loss) 1
9
24
34

Balance as of September 30, 2016 $ 2
$ (361 ) $ 141
$ (218 )

PSEG Other Comprehensive Income (Loss)
Nine Months Ended September 30, 2017
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 —
—
78
78

Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) (1 ) 18
(36 ) (19 )
Net Current Period Other Comprehensive Income (Loss) (1 ) 18
42
59

Balance as of September 30, 2017 $ 1
$ (380 ) $ 175
$ (204 )

PSEG Other Comprehensive Income (Loss)
Nine Months Ended September 30, 2016
Accumulated Other Comprehensive Income (Loss) Cash Flow Hedges Pension and OPEB Plans Available-for-Sale Securities Total
Millions
Balance as of December 31, 2015 $ —
$ (386 ) $ 91
$ (295 )
Other Comprehensive Income before Reclassifications 2
—
44
46

Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) —
25
6
31

Net Current Period Other Comprehensive Income (Loss) 2
25
50
77

Balance as of September 30, 2016 $ 2
$ (361 ) $ 141
$ (218 )

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Power’s effective tax rate as compared to the statutory rate of 28.11% was due primarily to the impact of tax credits on lower pre-tax income.

Power Other Comprehensive Income (Loss)
Three Months Ended September 30, 2017
Accumulated Other Comprehensive Income (Loss) Cash Flow Hedges Pension and OPEB Plans Available-for-Sale Securities Total
Millions
Balance as of June 30, 2017 $ —
$ (330 ) $ 158
$ (172 )
Other Comprehensive Income before Reclassifications —
—
24
24

Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) —
5
(9 ) (4 )
Net Current Period Other Comprehensive Income (Loss) —
5
15
20

Balance as of September 30, 2017 $ —
$ (325 ) $ 173
$ (152 )

Power Other Comprehensive Income (Loss)
Three Months Ended September 30, 2016
Accumulated Other Comprehensive Income (Loss) Cash Flow Hedges Pension and OPEB Plans Available-for-Sale Securities Total
Millions
Balance as of June 30, 2016 $ —
$ (313 ) $ 112
$ (201 )
Other Comprehensive Income before Reclassifications —
—
24
24

Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) —
7
(2 ) 5

Net Current Period Other Comprehensive Income (Loss) —
7
22
29

Balance as of September 30, 2016 $ —
$ (306 ) $ 134
$ (172 )

Power Other Comprehensive Income (Loss)
Nine Months Ended September 30, 2017
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 —
—
74
74

Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) —
15
(30 ) (15 )
Net Current Period Other Comprehensive Income (Loss) —
15
44
59

Balance as of September 30, 2017 $ —
$ (325 ) $ 173
$ (152 )

Power Other Comprehensive Income (Loss)
Nine Months Ended September 30, 2016
Accumulated Other Comprehensive Income (Loss) Cash Flow Hedges Pension and OPEB Plans Available-for-Sale Securities Total
Millions
Balance as of December 31, 2015 $ —
$ (327 ) $ 87
$ (240 )
Other Comprehensive Income before Reclassifications —
—
40
40

Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) —
21
7
28

Net Current Period Other Comprehensive Income (Loss) —
21
47
68

Balance as of September 30, 2016 $ —
$ (306 ) $ 134
$ (172 )

Tax Act

Effective January 1, 2018, the U.S. federal corporate 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 capital investments for income tax purposes. The Tax Act has led to lower customer rates due to lower income tax expense recoveries and the BPU and FERC have approved PSEG’s proposals to refund excess deferred income tax Regulatory Liabilities. The impact of the lower federal income tax rate on PSE&G was reflected in PSE&G’s distribution base rate proceeding and its 2018 transmission formula rate filings. 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 September 2019, the IRS released final and additional proposed regulations regarding the application of tax depreciation rules as amended by the Tax Act. We do not believe the final or proposed regulations materially impact our application of the rules.

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.

New Jersey State Tax Reform

In 2018, the State of New Jersey made significant 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. 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.

In 2019, 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.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Note 17. Accumulated Other Comprehensive Income (Loss), Net of Tax

PSEG Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement
Three Months Ended Nine Months Ended
Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) Location of Pre-Tax Amount In Statement of Operations September 30, 2017 September 30, 2017
Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount
Millions
Cash Flow Hedges
Interest Rate Swaps Interest Expense $ 2
$ (1 ) $ 1
$ 2
$ (1 ) $ 1

Total Cash Flow Hedges 2
(1 ) 1
2
(1 ) 1

Pension and OPEB Plans
Amortization of Prior Service (Cost) Credit O&M Expense 3
(1 ) 2
7
(3 ) 4

Amortization of Actuarial Loss O&M Expense (13 ) 5
(8 ) (37 ) 15
(22 )
Total Pension and OPEB Plans (10 ) 4
(6 ) (30 ) 12
(18 )
Available-for-Sale Securities
Realized Gains Other Income 29
(15 ) 14
99
(49 ) 50

Realized Losses Other Deductions (6 ) 2
(4 ) (19 ) 9
(10 )
OTTI OTTI (5 ) 3
(2 ) (9 ) 5
(4 )
Total Available-for-Sale Securities 18
(10 ) 8
71
(35 ) 36

Total $ 10
$ (7 ) $ 3
$ 43
$ (24 ) $ 19

PSEG Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement
Three Months Ended Nine Months Ended
Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) Location of Pre-Tax Amount In Statement of Operations September 30, 2016 September 30, 2016
Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount
Millions
Pension and OPEB Plans
Amortization of Prior Service (Cost) Credit O&M Expense $ 3
$ (2 ) $ 1
$ 9
$ (4 ) $ 5

Amortization of Actuarial Loss O&M Expense (17 ) 7
(10 ) (51 ) 21
(30 )
Total Pension and OPEB Plans (14 ) 5
(9 ) (42 ) 17
(25 )
Available-for-Sale Securities
Realized Gains Other Income 13
(6 ) 7
41
(20 ) 21

Realized Losses Other Deductions (5 ) 3
(2 ) (29 ) 15
(14 )
OTTI OTTI (5 ) 2
(3 ) (25 ) 12
(13 )
Total Available-for-Sale Securities 3
(1 ) 2
(13 ) 7
(6 )
Total $ (11 ) $ 4
$ (7 ) $ (55 ) $ 24
$ (31 )




PSEG	Three Months Ended September 30, 2019
Accumulated Other Comprehensive Income (Loss)	Cash Flow Hedges			Pension and OPEB Plans			Available-for-Sale Securities			Total
	Millions
Balance as of June 30, 2019	$	(18	)	$	(437	)	$	23		$	(432	)
Other Comprehensive Income before Reclassifications	—			(20		)	13			(7		)
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	1			3			(3		)	1
Net Current Period Other Comprehensive Income (Loss)	1			(17		)	10			(6		)
Balance as of September 30, 2019	$	(17	)	$	(454	)	$	33		$	(438	)

PSEG	Three Months Ended September 30, 2018
Accumulated Other Comprehensive Income (Loss)	Cash Flow Hedges			Pension and OPEB Plans			Available-for-Sale Securities			Total
	Millions
Balance as of June 30, 2018	$	(1	)	$	(391	)	$	(18	)	$	(410	)
Other Comprehensive Income before Reclassifications	—			—			(6		)	(6		)
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	—			7			2			9
Net Current Period Other Comprehensive Income (Loss)	—			7			(4		)	3
Balance as of September 30, 2018	$	(1	)	$	(384	)	$	(22	)	$	(407	)

PSEG	Nine Months Ended September 30, 2019
Accumulated Other Comprehensive Income (Loss)	Cash Flow Hedges			Pension and OPEB Plans			Available-for-Sale Securities			Total
	Millions
Balance as of December 31, 2018	$	(1	)	$	(360	)	$	(16	)	$	(377	)
Cumulative Effect Adjustment to Reclassify Stranded Tax Effects Resulting from the Change in the Federal Corporate Income Tax Rate to Retained Earnings	—			(81		)	—			(81		)
Current Period Other Comprehensive Income (Loss)
Other Comprehensive Income before Reclassifications	(17		)	(23		)	54			14
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	1			10			(5		)	6
Net Current Period Other Comprehensive Income (Loss)	(16		)	(13		)	49			20
Net Change in Accumulated Other Comprehensive Income (Loss)	(16		)	(94		)	49			(61		)
Balance as of September 30, 2019	$	(17	)	$	(454	)	$	33		$	(438	)

PSEG	Nine Months Ended September 30, 2018
Accumulated Other Comprehensive Income (Loss)	Cash Flow Hedges			Pension and OPEB Plans			Available-for-Sale Securities			Total
	Millions
Balance as of December 31, 2017	$	—		$	(406	)	$	177		$	(229	)
Cumulative Effect Adjustment to Reclassify Unrealized Net Gains on Equity Investments to Retained Earnings	—			—			(176		)	(176		)
Current Period Other Comprehensive Income (Loss)
Other Comprehensive Income before Reclassifications	(1		)	—			(28		)	(29		)
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	—			22			5			27
Net Current Period Other Comprehensive Income (Loss)	(1		)	22			(23		)	(2		)
Net Change in Accumulated Other Comprehensive Income (Loss)	(1		)	22			(199		)	(178		)
Balance as of September 30, 2018	$	(1	)	$	(384	)	$	(22	)	$	(407	)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)




PSEG Power	Three Months Ended September 30, 2019
Accumulated Other Comprehensive Income (Loss)	Cash Flow Hedges		Pension and OPEB Plans			Available-for-Sale Securities			Total
	Millions
Balance as of June 30, 2019	$	—	$	(372	)	$	18		$	(354	)
Other Comprehensive Income before Reclassifications	—		(14		)	10			(4		)
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	—		2			(3		)	(1		)
Net Current Period Other Comprehensive Income (Loss)	—		(12		)	7			(5		)
Balance as of September 30, 2019	$	—	$	(384	)	$	25		$	(359	)

PSEG Power	Three Months Ended September 30, 2018
Accumulated Other Comprehensive Income (Loss)	Cash Flow Hedges		Pension and OPEB Plans			Available-for-Sale Securities			Total
	Millions
Balance as of June 30, 2018	$	—	$	(335	)	$	(15	)	$	(350	)
Other Comprehensive Income before Reclassifications	—		—			(5		)	(5		)
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	—		7			1			8
Net Current Period Other Comprehensive Income (Loss)	—		7			(4		)	3
Balance as of September 30, 2018	$	—	$	(328	)	$	(19	)	$	(347	)

PSEG Power	Nine Months Ended September 30, 2019
Accumulated Other Comprehensive Income (Loss)	Cash Flow Hedges		Pension and OPEB Plans			Available-for-Sale Securities			Total
	Millions
Balance as of December 31, 2018	$	—	$	(306	)	$	(13	)	$	(319	)
Cumulative Effect Adjustment to Reclassify Stranded Tax Effects Resulting from the Change in the Federal Corporate Income Tax Rate to Retained Earnings	—		(69		)	—			(69		)
Current Period Other Comprehensive Income (Loss)
Other Comprehensive Income before Reclassifications	—		(17		)	42			25
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	—		8			(4		)	4
Net Current Period Other Comprehensive Income (Loss)	—		(9		)	38			29
Net Change in Accumulated Other Comprehensive Income (Loss)	—		(78		)	38			(40		)
Balance as of September 30, 2019	$	—	$	(384	)	$	25		$	(359	)

PSEG Power	Nine Months Ended September 30, 2018
Accumulated Other Comprehensive Income (Loss)	Cash Flow Hedges		Pension and OPEB Plans			Available-for-Sale Securities			Total
	Millions
Balance as of December 31, 2017	$	—	$	(347	)	$	175		$	(172	)
Cumulative Effect Adjustment to Reclassify Unrealized Net Gains on Equity Investments to Retained Earnings	—		—			(175		)	(175		)
Current Period Other Comprehensive Income (Loss)
Other Comprehensive Income before Reclassifications	—		—			(23		)	(23		)
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	—		19			4			23
Net Current Period Other Comprehensive Income (Loss)	—		19			(19		)	—
Net Change in Accumulated Other Comprehensive Income (Loss)	—		19			(194		)	(175		)
Balance as of September 30, 2018	$	—	$	(328	)	$	(19	)	$	(347	)

Power Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement
Three Months Ended Nine Months Ended
Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) Location of Pre-Tax Amount In Statement of Operations September 30, 2017 September 30, 2017
Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount
Millions
Pension and OPEB Plans
Amortization of Prior Service (Cost) Credit O&M Expense $ 2
$ (1 ) $ 1
$ 6
$ (3 ) $ 3

Amortization of Actuarial Loss O&M Expense (11 ) 5
(6 ) (32 ) 14
(18 )
Total Pension and OPEB Plans (9 ) 4
(5 ) (26 ) 11
(15 )
Available-for-Sale Securities
Realized Gains Other Income 29
(15 ) 14
86
(44 ) 42

Realized Losses Other Deductions (5 ) 2
(3 ) (15 ) 7
(8 )
OTTI OTTI (5 ) 3
(2 ) (9 ) 5
(4 )
Total Available-for-Sale Securities 19
(10 ) 9
62
(32 ) 30

Total $ 10
$ (6 ) $ 4
$ 36
$ (21 ) $ 15

Power Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement
Three Months Ended Nine Months Ended
Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) Location of Pre-Tax Amount In Statement of Operations September 30, 2016 September 30, 2016
Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount
Millions
Pension and OPEB Plans
Amortization of Prior Service (Cost) Credit O&M Expense $ 3
$ (1 ) $ 2
$ 8
$ (3 ) $ 5

Amortization of Actuarial Loss O&M Expense (15 ) 6
(9 ) (44 ) 18
(26 )
Total Pension and OPEB Plans (12 ) 5
(7 ) (36 ) 15
(21 )
Available-for-Sale Securities
Realized Gains Other Income 12
(5 ) 7
37
(18 ) 19

Realized Losses Other Deductions (4 ) 2
(2 ) (26 ) 13
(13 )
OTTI OTTI (5 ) 2
(3 ) (25 ) 12
(13 )
Total Available-for-Sale Securities 3
(1 ) 2
(14 ) 7
(7 )
Total $ (9 ) $ 4
$ (5 ) $ (50 ) $ 22
$ (28 )

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)




PSEG		Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement
		Three Months Ended									Nine Months Ended
Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	Location of Pre-Tax Amount In Statement of Operations	September 30, 2019									September 30, 2019
	Location of Pre-Tax Amount In Statement of Operations	Pre-Tax Amount			Tax (Expense) Benefit			After-Tax Amount			Pre-Tax Amount			Tax (Expense) Benefit			After-Tax Amount
		Millions
Cash Flow Hedges
Interest Rate Swaps	Interest Expense	$	(1	)	$	—		$	(1	)	$	(2	)	$	1		$	(1	)
Total Cash Flow Hedges		(1		)	—			(1		)	(2		)	1			(1		)
Pension and OPEB Plans
Amortization of Prior Service (Cost) Credit	Non-Operating Pension and OPEB Credits (Costs)	$	7		$	(2	)	$	5		$	20		$	(6	)	$	14
Amortization of Actuarial Loss	Non-Operating Pension and OPEB Credits (Costs)	(10		)	2			(8		)	(33		)	9			(24		)
Total Pension and OPEB Plans		(3		)	—			(3		)	(13		)	3			(10		)
Available-for-Sale Debt Securities
Realized Gains (Losses)	Net Gains (Losses) on Trust Investments	6			(3		)	3			9			(4		)	5
Total Available-for-Sale Debt Securities		6			(3		)	3			9			(4		)	5
Total		$	2		$	(3	)	$	(1	)	$	(6	)	$	—		$	(6	)




PSEG		Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement
		Three Months Ended								Nine Months Ended
Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	Location of Pre-Tax Amount In Statement of Operations	September 30, 2018								September 30, 2018
	Location of Pre-Tax Amount In Statement of Operations	Pre-Tax Amount			Tax (Expense) Benefit		After-Tax Amount			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)	$	1		$	—	$	1		$	3		$	—	$	3
Amortization of Actuarial Loss	Non-Operating Pension and OPEB Credits (Costs)	(11		)	3		(8		)	(34		)	9		(25		)
Total Pension and OPEB Plans		(10		)	3		(7		)	(31		)	9		(22		)
Available-for-Sale Debt Securities
Realized Gains (Losses)	Net Gains (Losses) on Trust Investments	(2		)	—		(2		)	(8		)	3		(5		)
Total Available-for-Sale Debt Securities		(2		)	—		(2		)	(8		)	3		(5		)
Total		$	(12	)	$	3	$	(9	)	$	(39	)	$	12	$	(27	)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)




PSEG Power		Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement
		Three Months Ended									Nine Months Ended
Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	Location of Pre-Tax Amount In Statement of Operations	September 30, 2019									September 30, 2019
	Location of Pre-Tax Amount In Statement of Operations	Pre-Tax Amount			Tax (Expense) Benefit			After-Tax Amount			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		$	17		$	(5	)	$	12
Amortization of Actuarial Loss	Non-Operating Pension and OPEB Credits (Costs)	(9		)	3			(6		)	(28		)	8			(20		)
Total Pension and OPEB Plans		(3		)	1			(2		)	(11		)	3			(8		)
Available-for-Sale Debt Securities
Realized Gains (Losses)	Net Gains (Losses) on Trust Investments	5			(2		)	3			7			(3		)	4
Total Available-for-Sale Debt Securities		5			(2		)	3			7			(3		)	4
Total		$	2		$	(1	)	$	1		$	(4	)	$	—		$	(4	)




PSEG Power		Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement
		Three Months Ended								Nine Months Ended
Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	Location of Pre-Tax Amount In Statement of Operations	September 30, 2018								September 30, 2018
	Location of Pre-Tax Amount In Statement of Operations	Pre-Tax Amount			Tax (Expense) Benefit		After-Tax Amount			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)	$	1		$	—	$	1		$	3		$	—	$	3
Amortization of Actuarial Loss	Non-Operating Pension and OPEB Credits (Costs)	(11		)	3		(8		)	(30		)	8		(22		)
Total Pension and OPEB Plans		(10		)	3		(7		)	(27		)	8		(19		)
Available-for-Sale Debt Securities
Realized Gains (Losses)	Net Gains (Losses) on Trust Investments	(1		)	—		(1		)	(7		)	3		(4		)
Total Available-for-Sale Debt Securities		(1		)	—		(1		)	(7		)	3		(4		)
Total		$	(11	)	$	3	$	(8	)	$	(34	)	$	11	$	(23	)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Note ~~16.~~18. 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 performance units or restricted stock units. The following table shows the effect of these stock options, performance units and restricted stock units on the weighted average number of shares outstanding used in calculating diluted EPS:




	Three Months Ended September 30,								Nine Months Ended September 30,
	2019				2018				2019				2018
	Basic		Diluted		Basic		Diluted		Basic		Diluted		Basic		Diluted
EPS Numerator (Millions):
Net Income	$	403	$	403	$	412	$	412	$	1,256	$	1,256	$	1,239	$	1,239
EPS Denominator (Millions):
Weighted Average Common Shares Outstanding	504		504		504		504		504		504		504		504
Effect of Stock Based Compensation Awards	—		3		—		3		—		3		—		3
Total Shares	504		507		504		507		504		507		504		507

EPS
Net Income	$	0.80	$	0.79	$	0.82	$	0.81	$	2.49	$	2.47	$	2.46	$	2.44

Three Months Ended September 30, Nine Months Ended September 30,
2017 2016 2017 2016
Basic Diluted Basic Diluted Basic Diluted Basic Diluted

EPS Numerator (Millions):

Net Income $ 395
$ 395
$ 327
$ 327
$ 618
$ 618
$ 985
$ 985

EPS Denominator (Millions):

Weighted Average Common Shares Outstanding 505
505
505
505
505
505
505
505

Effect of Stock Based Compensation Awards —
2
—
3
—
2
—
3

Total Shares 505
507
505
508
505
507
505
508

EPS
Net Income $ 0.78
$ 0.78
$ 0.65
$ 0.64
$ 1.22
$ 1.22
$ 1.95
$ 1.94

There were approximately 0.3 million for the three months and nine months ended September 30, 2017 and approximately 0.4 million for the three months and nine months ended September 30, 2016 of stock options excluded from the weighted average common shares used for diluted EPS due to their antidilutive effect.

Dividends




	Three Months Ended				Nine Months Ended
	September 30,				September 30,
Dividend Payments on Common Stock	2019		2018		2019		2018
Per Share	$	0.47	$	0.45	$	1.41	$	1.35
In Millions	$	238	$	227	$	713	$	682

Three Months Ended Nine Months Ended
September 30, September 30,
Dividend Payments on Common Stock 2017 2016 2017 2016
Per Share $ 0.43
$ 0.41
$ 1.29
$ 1.23

In Millions $ 217
$ 207
$ 652
$ 622

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Note ~~17.~~19. Financial Information by Business Segment

PSE&G Power Other (A) Eliminations (B) Consolidated Total
Millions
Three Months Ended September 30, 2017
Total Operating Revenues $ 1,509
$ 873
$ 135
$ (254 ) $ 2,263

Net Income (Loss) 246
136
13
—
395

Gross Additions to Long-Lived Assets 729
327
9
—
1,065

Nine Months Ended September 30, 2017
Operating Revenues $ 4,689
$ 3,086
$ 334
$ (1,121 ) $ 6,988

Net Income (Loss) 753
(131 ) (4 ) —
618

Gross Additions to Long-Lived Assets 2,118
903
25
—
3,046

Three Months Ended September 30, 2016
Total Operating Revenues $ 1,684
$ 1,075
$ 7
$ (316 ) $ 2,450

Net Income (Loss) 255
139
(67 ) —
327

Gross Additions to Long-Lived Assets 680
325
9
—
1,014

Nine Months Ended September 30, 2016
Operating Revenues $ 4,746
$ 3,102
$ 256
$ (1,133 ) $ 6,971

Net Income (Loss) 696
320
(31 ) —
985

Gross Additions to Long-Lived Assets 2,035
923
27
—
2,985

As of September 30, 2017
Total Assets $ 27,802
$ 11,631
$ 2,288
$ (564 ) $ 41,157

Investments in Equity Method Subsidiaries $ —
$ 90
$ —
$ —
$ 90

As of December 31, 2016
Total Assets $ 26,288
$ 12,193
$ 2,373
$ (784 ) $ 40,070

Investments in Equity Method Subsidiaries $ —
$ 102
$ —
$ —
$ 102




	PSE&G		PSEG Power		Other (A)			Eliminations (B)			Consolidated Total
	Millions
Three Months Ended September 30, 2019
Total Operating Revenues	$	1,604	$	771	$	151		$	(224	)	$	2,302
Net Income (Loss)	344		53		6			—			403
Gross Additions to Long-Lived Assets	608		168		3			—			779
Nine Months Ended September 30, 2019
Operating Revenues	$	5,018	$	3,270	$	379		$	(1,069	)	$	7,598
Net Income (Loss) (C)	974		309		(27		)	—			1,256
Gross Additions to Long-Lived Assets	1,866		507		10			—			2,383
Three Months Ended September 30, 2018
Total Operating Revenues	$	1,595	$	868	$	151		$	(220	)	$	2,394
Net Income (Loss)	278		125		9			—			412
Gross Additions to Long-Lived Assets	766		253		4			—			1,023
Nine Months Ended September 30, 2018
Operating Revenues	$	4,826	$	3,038	$	421		$	(1,057	)	$	7,228
Net Income (Loss)	828		400		11			—			1,239
Gross Additions to Long-Lived Assets	2,213		800		15			—			3,028
As of September 30, 2019
Total Assets	$	32,652	$	12,553	$	2,384		$	(774	)	$	46,815
Investments in Equity Method Subsidiaries	$	—	$	67	$	—		$	—		$	67
As of December 31, 2018
Total Assets	$	31,109	$	12,594	$	2,604		$	(981	)	$	45,326
Investments in Equity Method Subsidiaries	$	—	$	86	$	—		$	—		$	86


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

(B)

Intercompany eliminations primarily relate ~~primarily~~ to intercompany transactions between PSE&G and PSEG Power. No gains or losses are recorded on any intercompany transactions; rather, all intercompany transactions are at cost or, in the case of the BGS and BGSS contracts between PSE&G and Power, at rates prescribed by the BPU. For a further discussion of the intercompany transactions between PSE&G and PSEG Power, see Note ~~18.~~20. Related-Party Transactions.


(C)	Includes an after-tax loss of $286 million in the nine months ended September 30, 2019 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.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Note ~~18.~~20. 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:




	Three Months Ended				Nine Months Ended
	September 30,				September 30,
Related-Party Transactions	2019		2018		2019		2018
	Millions
Billings from Affiliates:
Net Billings from PSEG Power (A)	$	220	$	229	$	1,099	$	1,079
Administrative Billings from Services (B)	72		78		227		246
Total Billings from Affiliates	$	292	$	307	$	1,326	$	1,325

Three Months Ended Nine Months Ended
September 30, September 30,
Related-Party Transactions 2017 2016 2017 2016
Millions
Billings from Affiliates:
Net Billings from Power primarily through BGS and BGSS (A) $ 259
$ 320
$ 1,154
$ 1,162

Administrative Billings from Services (B) 82
73
226
224

Total Billings from Affiliates $ 341
$ 393
$ 1,380
$ 1,386




	As of		As of
Related-Party Transactions	September 30, 2019		December 31, 2018
	Millions
Receivable from PSEG (C)	$	12	$	123
Payable to PSEG Power (A)	$	152	$	245
Payable to Services (B)	56		76
Accounts Payable—Affiliated Companies	$	208	$	321
Working Capital Advances to Services (D)	$	33	$	33
Long-Term Accrued Taxes Payable	$	103	$	69

As of As of
Related-Party Transactions September 30, 2017 December 31, 2016
Millions
Receivables from PSEG (C) $ —
$ 76

Payable to Power (A) $ 86
$ 193

Payable to Services (B) 46
67

Payable to PSEG (C) 46
—

Accounts Payable—Affiliated Companies $ 178
$ 260

Working Capital Advances to Services (D) $ 33
$ 33

Long-Term Accrued Taxes Payable
$ 83
$ 130

PSEG Power

The financial statements for PSEG Power include transactions with related parties presented as follows:




	Three Months Ended				Nine Months Ended
	September 30,				September 30,
Related-Party Transactions	2019		2018		2019		2018
	Millions
Billings to Affiliates:
Net Billings to PSE&G (A)	$	220	$	229	$	1,099	$	1,079
Billings from Affiliates:
Administrative Billings from Services (B)	$	41	$	38	$	132	$	113

Three Months Ended Nine Months Ended
September 30, September 30,
Related-Party Transactions 2017 2016 2017 2016
Millions
Billings to Affiliates:
Net Billings to PSE&G primarily through BGS and BGSS (A) $ 259
$ 320
$ 1,154
$ 1,162

Billings from Affiliates:
Administrative Billings from Services (B) $ 39
$ 44
$ 117
$ 134




	As of		As of
Related-Party Transactions	September 30, 2019		December 31, 2018
	Millions
Receivable from PSE&G (A)	$	152	$	245
Receivable from PSEG (C)	81		29
Accounts Receivable—Affiliated Companies	$	233	$	274
Payable to Services (B)	$	20	$	16
Accounts Payable—Affiliated Companies	$	20	$	16
Short-Term Loan to (from) Affiliate (E)	$	86	$	(193	)
Working Capital Advances to Services (D)	$	17	$	17
Long-Term Accrued Taxes Payable	$	101	$	76

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

As of As of
Related-Party Transactions September 30, 2017 December 31, 2016
Millions
Receivables from PSE&G (A) $ 86
$ 193

Receivables from PSEG (C) —
12

Accounts Receivable—Affiliated Companies $ 86
$ 205

Payable to Services (B) $ 17
$ 25

Payable to PSEG (C) 111
—

Accounts Payable—Affiliated Companies $ 128
$ 25

Short-Term Loan Due (to) from Affiliate (E) $ 1
$ 87

Working Capital Advances to Services (D) $ 17
$ 17

Long-Term Accrued Taxes Payable
$ 57
$ 77

(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.~~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, such as pension and OPEB 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 Condensed Consolidated Balance Sheets.


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

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Note ~~19.~~21. 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 September 30, ~~2017~~2019 and December 31, ~~2016~~2018 and for the three months and nine months ended September 30, ~~2017~~2019 and ~~2016.~~2018.

Power
Guarantor
Subsidiaries

Other
Subsidiaries

Consolidating
Adjustments
Total
Millions
Three Months Ended September 30, 2017
Operating Revenues $ —
$ 856
$ 46
$ (29 ) $ 873

Operating Expenses 2
643
44
(29 ) 660

Operating Income (Loss) (2 ) 213
2
—
213

Equity Earnings (Losses) of Subsidiaries 143
(3 ) 3
(140 ) 3

Other Income 24
58
(2 ) (37 ) 43

Other Deductions —
(8 ) —
—
(8 )
Other-Than-Temporary Impairments —
(5 ) —
—
(5 )
Interest Expense (32 ) (12 ) (5 ) 37
(12 )
Income Tax Benefit (Expense) 3
(103 ) 2
—
(98 )
Net Income (Loss) $ 136
$ 140
$ —
$ (140 ) $ 136

Comprehensive Income (Loss) $ 156
$ 154
$ —
$ (154 ) $ 156

Nine Months Ended September 30, 2017
Operating Revenues $ —
$ 3,036
$ 145
$ (95 ) $ 3,086

Operating Expenses 4
3,315
139
(95 ) 3,363

Operating Income (Loss) (4 ) (279 ) 6
—
(277 )
Equity Earnings (Losses) of Subsidiaries (111 ) (8 ) 11
119
11

Other Income 71
155
—
(99 ) 127

Other Deductions (1 ) (21 ) —
—
(22 )
Other-Than-Temporary Impairments —
(9 ) —
—
(9 )
Interest Expense (96 ) (30 ) (14 ) 99
(41 )
Income Tax Benefit (Expense) 10
68
2
—
80

Net Income (Loss) $ (131 ) $ (124 ) $ 5
$ 119
$ (131 )
Comprehensive Income (Loss) $ (72 ) $ (80 ) $ 5
$ 75
$ (72 )
Nine Months Ended September 30, 2017

Net Cash Provided By (Used In)
   Operating Activities
$ (55 ) $ 1,159
$ 142
$ 3
$ 1,249

Net Cash Provided By (Used In)
   Investing Activities
$ 738
$ (289 ) $ (343 ) $ (990 ) $ (884 )

Net Cash Provided By (Used In)
   Financing Activities
$ (683 ) $ (869 ) $ 211
$ 987
$ (354 )




	PSEG Power			Guarantor Subsidiaries			Other Subsidiaries			Consolidating Adjustments			Total
	Millions
Three Months Ended September 30, 2019
Operating Revenues	$	—		$	748		$	78		$	(55	)	$	771
Operating Expenses	—			672			75			(55		)	692
Operating Income (Loss)	—			76			3			—			79
Equity Earnings (Losses) of Subsidiaries	69			(10		)	3			(59		)	3
Net Gains (Losses) on Trust Investments	1			(5		)	—			—			(4		)
Other Income (Deductions)	42			53			—			(80		)	15
Non-Operating Pension and OPEB Credits (Costs)	—			7			1			—			8
Interest Expense	(71		)	(27		)	(16		)	80			(34		)
Income Tax Benefit (Expense)	12			(30		)	4			—			(14		)
Net Income (Loss)	$	53		$	64		$	(5	)	$	(59	)	$	53
Comprehensive Income (Loss)	$	48		$	70		$	(5	)	$	(65	)	$	48
Nine Months Ended September 30, 2019
Operating Revenues	$	—		$	3,212		$	200		$	(142	)	$	3,270
Operating Expenses	3			2,914			201			(142		)	2,976
Operating Income (Loss)	(3		)	298			(1		)	—			294
Equity Earnings (Losses) of Subsidiaries	363			(28		)	10			(335		)	10
Net Gains (Losses) on Trust Investments	2			158			—			—			160
Other Income (Deductions)	134			166			—			(257		)	43
Non-Operating Pension and OPEB Credits (Costs)	—			13			1			—			14
Interest Expense	(224		)	(82		)	(36		)	257			(85		)
Income Tax Benefit (Expense)	37			(175		)	11			—			(127		)
Net Income (Loss)	$	309		$	350		$	(15	)	$	(335	)	$	309
Comprehensive Income (Loss)	$	338		$	384		$	(15	)	$	(369	)	$	338
Nine Months Ended September 30, 2019
Net Cash Provided By (Used In) Operating Activities	$	171		$	1,345		$	75		$	(229	)	$	1,362
Net Cash Provided By (Used In) Investing Activities	$	154		$	(708	)	$	(253	)	$	222		$	(585	)
Net Cash Provided By (Used In) Financing Activities	$	(256	)	$	(640	)	$	170		$	7		$	(719	)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)




	PSEG Power			Guarantor Subsidiaries			Other Subsidiaries			Consolidating Adjustments			Total
	Millions
Three Months Ended September 30, 2018
Operating Revenues	$	—		$	849		$	59		$	(40	)	$	868
Operating Expenses	2			733			61			(40		)	756
Operating Income (Loss)	(2		)	116			(2		)	—			112
Equity Earnings (Losses) of Subsidiaries	117			(7		)	5			(110		)	5
Net Gains (Losses) on Trust Investments	—			45			(1		)	—			44
Other Income (Deductions)	40			45			—			(71		)	14
Non-Operating Pension and OPEB Credits (Costs)	—			4			—			—			4
Interest Expense	(65		)	(28		)	(7		)	71			(29		)
Income Tax Benefit (Expense)	35			(64		)	4			—			(25		)
Net Income (Loss)	$	125		$	111		$	(1	)	$	(110	)	$	125
Comprehensive Income (Loss)	$	128		$	107		$	(1	)	$	(106	)	$	128
Nine Months Ended September 30, 2018
Operating Revenues	$	—		$	2,982		$	161		$	(105	)	$	3,038
Operating Expenses	5			2,493			162			(105		)	2,555
Operating Income (Loss)	(5		)	489			(1		)	—			483
Equity Earnings (Losses) of Subsidiaries	406			(14		)	12			(392		)	12
Net Gains (Losses) on Trust Investments	—			31			(1		)	—			30
Other Income (Deductions)	116			118			—			(196		)	38
Non-Operating Pension and OPEB Credits (Costs)	—			10			1			—			11
Interest Expense	(161		)	(64		)	(18		)	196			(47		)
Income Tax Benefit (Expense)	44			(179		)	8			—			(127		)
Net Income (Loss)	$	400		$	391		$	1		$	(392	)	$	400
Comprehensive Income (Loss)	$	400		$	374		$	1		$	(375	)	$	400
Nine Months Ended September 30, 2018
Net Cash Provided By (Used In) Operating Activities	$	(255	)	$	1,169		$	(26	)	$	117		$	1,005
Net Cash Provided By (Used In) Investing Activities	$	(417	)	$	(1,132	)	$	(290	)	$	829		$	(1,010	)
Net Cash Provided By (Used In) Financing Activities	$	672		$	(32	)	$	320		$	(946	)	$	14

Power
Guarantor
Subsidiaries

Other
Subsidiaries

Consolidating
Adjustments
Total
Millions
Three Months Ended September 30, 2016
Operating Revenues $ —
$ 1,059
$ 43
$ (27 ) $ 1,075

Operating Expenses (2 ) 826
40
(27 ) 837

Operating Income (Loss) 2
233
3
—
238

Equity Earnings (Losses) of Subsidiaries 143
(1 ) 3
(142 ) 3

Other Income 18
26
—
(21 ) 23

Other Deductions (2 ) (4 ) —
—
(6 )
Other-Than-Temporary Impairments —
(5 ) —
—
(5 )
Interest Expense (30 ) (12 ) (3 ) 21
(24 )
Income Tax Benefit (Expense) 8
(97 ) (1 ) —
(90 )
Net Income (Loss) $ 139
$ 140
$ 2
$ (142 ) $ 139

Comprehensive Income (Loss) $ 168
$ 161
$ 2
$ (163 ) $ 168

Nine Months Ended September 30, 2016
Operating Revenues $ —
$ 3,061
$ 131
$ (90 ) $ 3,102

Operating Expenses 10
2,494
119
(90 ) 2,533

Operating Income (Loss) (10 ) 567
12
—
569

Equity Earnings (Losses) of Subsidiaries 347
(1 ) 9
(346 ) 9

Other Income 52
88
—
(66 ) 74

Other Deductions (2 ) (31 ) —
—
(33 )
Other-Than-Temporary Impairments —
(25 ) —
—
(25 )
Interest Expense (91 ) (29 ) (12 ) 66
(66 )
Income Tax Benefit (Expense) 24
(234 ) 2
—
(208 )
Net Income (Loss) $ 320
$ 335
$ 11
$ (346 ) $ 320

Comprehensive Income (Loss) $ 388
$ 381
$ 11
$ (392 ) $ 388

Nine Months Ended September 30, 2016

Net Cash Provided By (Used In)
   Operating Activities
$ 175
$ 1,261
$ 234
$ (410 ) $ 1,260

Net Cash Provided By (Used In)
   Investing Activities
$ (588 ) $ (1,166 ) $ (549 ) $ 1,152
$ (1,151 )

Net Cash Provided By (Used In)
   Financing Activities
$ 413
$ (95 ) $ 315
$ (742 ) $ (109 )

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)




	PSEG Power		Guarantor Subsidiaries		Other Subsidiaries		Consolidating Adjustments			Total
	Millions
As of September 30, 2019
Current Assets	$	4,142	$	1,459	$	327	$	(4,497	)	$	1,431
Property, Plant and Equipment, net	44		4,484		3,967		—			8,495
Investment in Subsidiaries	5,184		1,078		—		(6,262		)	—
Noncurrent Assets	289		2,526		116		(304		)	2,627
Total Assets	$	9,659	$	9,547	$	4,410	$	(11,063	)	$	12,553
Current Liabilities	$	903	$	2,467	$	2,153	$	(4,497	)	$	1,026
Noncurrent Liabilities	550		2,216		859		(304		)	3,321
Long-Term Debt	2,433		—		—		—			2,433
Member’s Equity	5,773		4,864		1,398		(6,262		)	5,773
Total Liabilities and Member’s Equity	$	9,659	$	9,547	$	4,410	$	(11,063	)	$	12,553
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

Power
Guarantor
Subsidiaries

Other
Subsidiaries

Consolidating
Adjustments
Total
Millions
As of September 30, 2017
Current Assets $ 4,089
$ 1,324
$ 182
$ (4,433 ) $ 1,162

Property, Plant and Equipment, net 57
5,408
2,607
—
8,072

Investment in Subsidiaries 4,168
338
—
(4,506 ) —

Noncurrent Assets 184
2,211
116
(114 ) 2,397

Total Assets $ 8,498
$ 9,281
$ 2,905
$ (9,053 ) $ 11,631

Current Liabilities $ 233
$ 3,221
$ 1,743
$ (4,433 ) $ 764

Noncurrent Liabilities 503
2,192
524
(114 ) 3,105

Long-Term Debt 2,385
—
—
—
2,385

Member’s Equity 5,377
3,868
638
(4,506 ) 5,377

Total Liabilities and Member’s Equity $ 8,498
$ 9,281
$ 2,905
$ (9,053 ) $ 11,631

As of December 31, 2016
Current Assets $ 4,412
$ 1,593
$ 152
$ (4,697 ) $ 1,460

Property, Plant and Equipment, net 55
6,145
2,320
—
8,520

Investment in Subsidiaries 4,249
344
—
(4,593 ) —

Noncurrent Assets 168
2,016
129
(100 ) 2,213

Total Assets $ 8,884
$ 10,098
$ 2,601
$ (9,390 ) $ 12,193

Current Liabilities $ 171
$ 3,752
$ 1,454
$ (4,697 ) $ 680

Noncurrent Liabilities 532
2,398
502
(100 ) 3,332

Long-Term Debt 2,382
—
—
—
2,382

Member’s Equity 5,799
3,948
645
(4,593 ) 5,799

Total Liabilities and Member’s Equity $ 8,884
$ 10,098
$ 2,601
$ (9,390 ) $ 12,193


ITEM 2.	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 ~~(Power)~~(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 solar generation projects and has implemented energy efficiency and related programs in New Jersey, which are regulated by the BPU, and

~~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, Power owns and operates solar generation in various states. 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.

•

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 ~~include PSEG Energy Holdings L.L.C. (Energy Holdings), which primarily has investments in leveraged leases;~~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~~an Operations ~~and~~ 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 Part I, Item 1. Business of our ~~2016~~2018 Annual Report on 10-K (Form 10-K) 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 Part I, Item 1A. Risk Factors of Form 10-K provides information about factors that could have a material adverse impact on our businesses. The following supplements that discussion and the discussion included in the Executive Overview of ~~2016~~2018 and Future Outlook provided in Item 7 in our Form 10-K by describing significant events and business developments that have occurred during ~~2017~~2019 and changes to the key factors that we expect may drive our future performance. The following discussion refers to the Condensed Consolidated Financial Statements (Statements) and the Related Notes to Condensed Consolidated Financial Statements (Notes). This discussion should be read in conjunction with such Statements, Notes and the ~~2016~~ Form 10-K.

EXECUTIVE OVERVIEW OF ~~2017~~2019 AND FUTURE OUTLOOK

Our business plan is designed to achieve growth while managing the risks associated with fluctuating commodity prices and changes in customer demand. ~~We continue~~

PSE&G

At PSE&G, our focus is 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, including:~~

i~~mproving utility operations through investment in T&D and other infrastructure projects designed to enhance system~~enhancing reliability and resiliency ~~and to meet~~of our T&D system, meeting customer expectations and supporting public policy objectives

by investing capital in T&D infrastructure and clean energy programs. Over the past few years, our investments have altered our business mix to reflect a higher percentage of earnings contribution by PSE&G. Based upon the settlement of the Energy Strong Program II (ES II) noted below, PSE&G has narrowed its five-year capital expenditure range to $12 billion to $14.5 billion, resulting in an expected annual rate base growth of 7.5% to 8.5%.

~~maintaining~~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 ~~expanding a reliable generation fleet~~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 ~~flexibility~~remaining $300 million to ~~utilize~~be recovered through a ~~diverse~~future base rate proceeding. As part of the settlement approved by the BPU, 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.

In June 2018, we filed for our ES II, a proposed five-year $2.5 billion program to harden, modernize and improve the resiliency of our electric and gas distribution systems. In September 2019, the BPU approved an $842 million program for gas and electric projects which will begin in the fourth quarter of 2019 and is expected to be completed at the end of 2023. As part of the settlement agreement, 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 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 related to implementing provisions of the Clean Energy Act related to energy efficiency. The BPU is also addressing stakeholder input as it works to finalize New Jersey’s Energy Master Plan, currently scheduled to be released in December 2019. As a result, the CEF-EE filing remains pending before the BPU. In September 2019, the BPU approved a settlement reached with the parties in the CEF-EE that extends the matter into March 2020, and that authorizes, in the interim, an additional $27 million investment for PSE&G to continue delivering four of its existing EE programs for an additional year.

In November 2018, the New Jersey Division of Rate Counsel (Rate Counsel) filed a motion to dismiss the CEF-EC filing on the basis that the BPU announced a moratorium on electric distribution companies’ advanced meter infrastructure programs. In December 2018, Rate Counsel filed a motion to stay the CEF-EV/ES filing, arguing that the BPU should conclude other regulatory proceedings addressing EVs and ES, including the new Energy Master Plan and initiatives required by the Clean Energy Act, before it rules on PSE&G’s program. We opposed Rate Counsel’s motions, asking for the BPU to permit these filings to proceed. There is no timetable for the BPU to decide on Rate Counsel’s motions. We continue to pursue procedural schedules to initiate the BPU’s review of our proposed CEF-EV/ES and CEF-EC 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 2019-2021 is $3.6 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. 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. Approximately 75% of PSEG Power’s expected gross margin in 2019 relates to hedging of our energy margin, our expected revenues from the capacity market mechanisms, Zero Emission Certificate revenues that commenced in April 2019 and certain ancillary service payments such as reactive power.

We commenced commercial operations of Keys Energy Center (Keys) and Sewaren 7 in mid-2018. Upon the start of commercial operation of Bridgeport Harbor Station Unit 5 (BH5) in June 2019, PSEG Power completed its 1,800 MW combined cycle gas turbine construction program. These additions to our fleet both expand our geographic diversity and adjust our fuel mix and enhance the environmental profile and overall efficiency of ~~fuels which allows~~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 ~~respond~~take advantage of opportunities in a rapidly evolving market as we remain diligent in managing costs. In the first nine months of 2019, our

utility continued its efforts to ~~market~~control costs while maintaining strong operational performance, including ranking in the top quartile among large utilities in the East in JD Power’s 2019 Electric Utility Residential Customer Satisfaction Study,

diverse fuel mix and dispatch flexibility allowed us to generate approximately 43 terawatt hours while addressing fuel availability and price volatility, and ~~capitalize~~

total nuclear fleet achieved a capacity factor of 91.0%.

~~Table~~We expect to be able to fund our planned capital requirements, as described in Liquidity and Capital Resources, and the impacts of ~~Contents~~

Financial Strength

Our financial strength is predicated on ~~opportunities~~a solid balance sheet, positive operating cash flow and reasonable risk-adjusted returns on increased investment. Our financial position remained strong during the first nine months of 2019 as ~~they arise.~~we

maintained sufficient liquidity,

maintained solid investment grade credit ratings, and

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

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 Tax Legislation below.

Financial Results

As a result of the settlement of PSE&G’s distribution base rate proceeding in October 2018, with new rates effective November 1, 2018, PSE&G’s overall 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 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.

PSE&G also filed a revised 2019 Annual Transmission Formula Rate 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, decreases overall annual transmission revenues by approximately $54 million, subject to true-up.

The results for PSEG, PSE&G and PSEG Power for the three months and nine months ended September 30, ~~2017~~2019 and ~~2016~~2018 are presented as follows:

Three Months Ended Nine Months Ended
September 30, September 30,
Earnings (Losses) 2017 2016 2017 2016
Millions
PSE&G $ 246
$ 255
$ 753
$ 696

Power (A) 136
139
(131 ) 320

Other (B) 13
(67 ) (4 ) (31 )
PSEG Net Income $ 395
$ 327
$ 618
$ 985

PSEG Net Income Per Share (Diluted) $ 0.78
$ 0.64
$ 1.22
$ 1.94




	Three Months Ended				Nine Months Ended
	September 30,				September 30,
Earnings (Losses)	2019		2018		2019			2018
	Millions
PSE&G	$	344	$	278	$	974		$	828
PSEG Power (A)	53		125		309			400
Other (B)	6		9		(27		)	11
PSEG Net Income	$	403	$	412	$	1,256		$	1,239

PSEG Net Income Per Share (Diluted)	$	0.79	$	0.81	$	2.47		$	2.44

(A)

Includes an after-tax ~~expenses~~loss of ~~$5 million and $568~~$286 million in the ~~three months and~~ nine months ended September 30, ~~2017, respectively, and after-tax expenses of $67 million for the three months and nine months ended September 30, 2016~~2019 related to the ~~early retirement~~sale of PSEG Power’s ~~Hudson~~ownership interests in the Keystone and ~~Mercer coal/gas~~Conemaugh fossil generation plants. See Item 1. Note 3.4. Early Plant ~~Retirements~~Retirements/Asset Dispositions for additional information.

(B)

Other includes after-tax activities at the parent company, PSEG LI, and Energy Holdings as well as intercompany eliminations. Energy Holdings recorded after-tax charges related to its investments in leveraged leases of ~~$45~~$32 million ~~for~~and $14 million in the nine months ended September 30, ~~2017,~~2019 and ~~an after-tax impairment of $86 million for the three months and nine months ended September 30, 2016 related to its investments in NRG REMA, LLC’s (REMA) leveraged leases.~~2018, respectively. See Item 1. Note 6.8. Financing Receivables for additional information.

PSEG Power’s results above include ~~the realized gains, losses and earnings on~~ the Nuclear Decommissioning Trust (NDT) Fund ~~and other related NDT~~ 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 ~~include the~~attributable to changes related to the NDT Fund and MTM are shown in the following table:

Three Months Ended Nine Months Ended
September 30, September 30,
2017 2016 2017 2016
Millions, after tax
NDT Fund Income (Expense) (A) (B) $ 10
$ 2
$ 32
$ (4 )
Non-Trading MTM Gains (Losses) (C) $ (27 ) $ 34
$ —
$ (54 )




	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2019			2018			2019		2018
	Millions, after tax
NDT Fund Income (Expense) (A) (B)	$	(4	)	$	27		$	97	$	16
Non-Trading MTM Gains (Losses) (C)	$	(88	)	$	(96	)	$	140	$	(59	)

(A)

NDT Fund Income (Expense) includes ~~the realized~~ gains and losses on NDT securities which are recorded in Net Gains (Losses) on Trust Investments. See Item 1. Note 9. Trust Investments for additional information. NDT Fund Income (Expense) also includes interest and dividend income and other costs related to the NDT Fund ~~which are~~ recorded in Other Income ~~and Deductions, and impairments on certain NDT securities recorded as Other-Than-Temporary Impairments. Interest~~(Deductions), interest accretion expense on PSEG Power’s nuclear Asset Retirement Obligation (ARO) is recorded in Operation and Maintenance (O&M) Expense and the depreciation related to the ARO asset is recorded in Depreciation and Amortization (D&A) Expense.


(B)	Net of tax (expense) benefit of ~~$(12) million, $(2) million, $(37)~~$0 million and $0$(16) million for the three months and $(67) million and $(12) million for the nine months ended September 30, ~~2017~~2019 and ~~2016,~~2018, respectively.


(C)	Net of tax (expense) benefit of ~~$19 million $(24) million, $0~~$33 million and $37 million for the three months and $(55) million and $23 million for the nine months ended September 30, ~~2017~~2019 and ~~2016,~~2018, respectively.

Our ~~$68~~$9 million ~~increase~~decrease in Net Income for the three months ended September 30, ~~2017~~2019 was driven ~~primarily~~largely by


•	unrealizedlosses in 2019 as compared to unrealized gains in 2018 on equity securities on the NDT Fund at PSEG Power,

lower volumes of electricity sold at lower average prices in the PJM region and under the BGS contracts as well as a decrease in capacity revenue at PSEG Power, and

an ~~impairment~~income tax benefit in ~~2016 related~~2018 resulting from the reserve for uncertain tax positions in connection with a nuclear carryback claim and closure of the 2011 and 2012 federal tax audit at PSEG Power, partially offset by

higher earnings due to investments in ~~certain leveraged leases at Energy Holdings,~~

~~higher charges in 2016 related to early retirement~~T&D programs and the favorable impact of new rates effective November 1, 2018 as a result of the BPU’s approval of our ~~Hudson and Mercer coal/gas generation units~~distribution base rate proceeding at ~~Power,~~PSE&G,

~~lower generation costs driven by lower natural gas costs and congestion costs,~~the favorable impact of retiree medical plan benefit changes implemented in 2019, and

~~higher transmission revenues.~~

~~These favorable variances were partially offset by~~

~~lower sales of electricity sold under the Basic Generation Service contract and~~revenue from Zero Emissions Certificates (ZECs) starting in ~~PJM, and~~

~~MTMlossesin 2017 as compared to MTM gains in 2016.~~

mid-April 2019 at PSEG Power.

Our ~~$367~~$17 million ~~decrease~~increase in Net Income for the nine months ended September 30, ~~2017~~2019 was driven primarily by

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

net gains in 2019 on equity securities in the NDT Fund at PSEG Power,

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

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

revenue from ZECs starting in mid-April 2019 at PSEG Power, largely offset by ~~higher charges, primarily accelerated depreciation,~~

a loss related to the ~~early retirement~~sale of ~~our Hudson~~PSEG Power’s ownership interests in the Keystone and ~~Mercer coal/gas~~Conemaugh generation ~~units at Power. These decreases were partially offset by~~plants in 2019.

~~lower O&M Expense due to cost control efforts,~~

~~lower charges related to investments in certain leveraged leases at Energy Holdings,~~

~~MTM losses in 2016, and~~

~~higher NDT gains and lower NDT losses in 2017.~~

During the first nine months of 2017, we maintained a strong balance sheet. We continued to effectively deploy capital without the need for additional equity, while our solid credit ratings aided our ability to access capital and credit markets. The greater emphasis on capital spending in recent years for projects on which we receive contemporaneous returns at PSE&G ~~our regulated utility, in recent years~~ has yielded strong results, which when combined with the cash flow generated by PSEG Power, ~~our merchant generator and power marketer,~~ has allowed us to increase our ~~dividend.~~dividend annually. These actions to ~~transition our business to~~ meet customer needs, market conditions and investor expectations reflect our long-term approach to managing our company. ~~Our~~We continue our focus ~~has~~on operational excellence, financial strength and disciplined investment. These guiding principles have provided the base from which we have been able to ~~invest~~execute our strategic initiatives.

Disciplined Investment

We utilize rigorous criteria when deploying capital ~~in T&D~~ and other infrastructure projects aimed at maintaining service reliability to our customers and bolstering our system resiliency. At Power, we strive to improve performance and reduce costs in order to enhance the value of our generation fleet in light of low gas prices, environmental considerations and competitive market forces that reward efficiency and reliability.

~~At PSE&G, we continue~~seek to invest in ~~transmission projects~~areas that ~~focus on reliability improvements~~complement our existing business and ~~replacement of aging~~provide reasonable risk-adjusted returns. These areas include upgrading our energy infrastructure ~~including~~and improving our ~~$275 million Newark Switch project that was approved by PJM in July 2017. We also continue~~environmental footprint to ~~make investments to improve~~align with public policy objectives. In the resiliency of our gas and electric distribution system as part of our Energy Strong program that was approved by the BPU in 2014 and to seek recovery on such investments. We also continue to modernize PSE&G’s gas distribution systems as part of our Gas System Modernization Program (GSMP) that was approved by the BPU in late 2015. Over the past few years, these types of investments have altered our business mix to reflect a higher percentage of earnings contribution by PSE&G.

As a result of our Energy Strong Order from the BPU, we are required to file a distribution base rate case. Following discussions with BPU Staff and Rate Counsel, and as approved by the BPU at its October 20, 2017 meeting, the deadline for filing PSE&G’s distribution base rate case was moved from November 1, 2017 to December 1, 2017. The initial filing will now be based upon three months of actual data andfirst nine months of ~~forecasted data updated for actual data throughout the proceeding. The distribution base rate case will provide PSE&G the opportunity~~2019, we

made additional investments in T&D infrastructure projects,

continued to recover investments made since its last distribution base rate case, including investments that were not recovered through clauses, such as the stipulated base investment associated with GSMP, the portion of Energy Strong investment not recovered through the clause, and investments that exceeded our depreciation levels in revenues. Recovery of these investments, coupled with updates to O&M and other adjustments, are anticipated to result in a proposed mid-single digit percentage increase in PSE&G distribution revenues. The distribution base rate case filing will include a test year through June 30, 2018 and will request the inclusion of known and measurable changes in rate base through December 31, 2018, a 10.3% return on equity (ROE) and a capitalization structure with a 54% equity component, and we expect to request new rates effective October 1, 2018. As part of the filing, we will also request approval to decouple electric and gas revenues from sales volumes for most distribution customer classes. We cannot predict the outcome of this proceeding.

In July 2017, we filed a petition with the BPU for GSMP II, a five-year extension of GSMP, which would accelerate the pace of replacement of our aging cast iron and unprotected steel mains and associated service. We proposed to invest up to $540 million per year over this five-year program beginning in 2019. In August 2017, the BPU approved our request for an extension ofexecute our Energy Efficiency ~~program.~~and other existing BPU-approved utility programs, and

~~Although~~completed construction and placed into service our BH5 generation project, the weather in the first three months of 2017 was warmer than normal, Power’s results saw a continuing benefit from access to natural gas supplies through existing firm pipeline transportation contracts. Power manages these contracts for the benefit of PSE&G’s customers through the basic gas supply (BGSS) arrangement. The contracts are sized to provide for delivery of a reliable gas supply to PSE&G customers on peak winter demand days. When pipeline capacity beyond the customers’ needs is available, Power can use it to make third-party sales and if excess volume remains after the third-party sales, supply gas to its generating units in New Jersey. Alternatively, gas supply and pipeline capacity constraints could adversely impact our ability to meet the needsfinal stage of our ~~utility customers and generating units.~~

~~Power’s hedging practices and ability to capitalize on market opportunities help us to balance some of the volatility of the merchant power business. Power’s hedging~~investment program in combination with expected revenues from the capacity market mechanisms and certain ancillary service payments, such as reactive power, has secured approximately 60% of its estimated gross margin for the 2017-2019 period.

Our investments in Keys Energy Center (Keys), Sewaren 7 and Bridgeport Harbor Station unit 5 (BH5) reflect our recognition of the value of opportunistic growth in the Power business. These highly efficient additions to our fleet both expand our geographic diversity and adjust our fuel mix and are expected to improve our financial performance.

Since 2013, several nuclear generating stations in the United States have closed or announced early retirement due to economic reasons, or have announced as being at risk for early retirement. This situation is generally due to the decline in market prices of energy, resulting from low naturalcombined cycle gas prices driven by the growth of shale gas production since 2007, the continuing cost of regulatory compliance and enhanced security for nuclear facilities and both federal and state-level policies that provide financial incentives to renewable energy such as wind and solar, but generally do not apply to nuclear generating stations. These trends have significantly reduced the revenues of nuclear generating stations while limiting their ability to reduce the unit cost of production. This may result in the electric generation industry experiencing a shift from nuclear generation to natural gas-fired generation, creating less diversity of the generation fleet.

If the market trends noted above continue or worsen, our New Jersey nuclear generating units could cease being economically competitive, which may cause us to retire such units prior to the end of their useful lives. The costs associated with any such potential retirement, which may include, among other things, accelerated D&A or impairment charges, accelerated asset retirement costs, severance costs, environmental remediation costs, and additional funding of NDT funds would likely have a material adverse impact on future financial results. We continue to advocate for sound policies that recognize nuclear power as a source of reliable and clean energy, free of air emissions and an important part of a diverse and reliable energy portfolio. See Item 1. Note 3. Early Plant Retirements for additional information.

In addition, a number of states have either taken action or are investigating the situation faced by nuclear generating units. Recently, courts in Illinois and New York upheld challenges to the programs which established zero emissions credits, recognizing the importance of nuclear units for providing clean energy, free of air emissions.

In September 2017, the Secretary of the U.S. Department of Energy (DOE) issued a Notice of Proposed Rulemaking (NOPR) directing FERC to act within 60 days to develop a mechanism that would allow for the recovery of costs of fuel-secure generation units such as nuclear and coal. To be eligible for compensation under the NOPR, units must be able to provide certain essentialenergy and ancillary reliability services, have a 90-day fuel supply on site and not subject to cost-of-service rate regulation by any State or local authority. PSEG is evaluating the potential effects this NOPR could have on its generating fleet. PSEG filed comments in support of the DOE’s NOPR and contended that it should be implemented immediately as an interim measure to prevent the premature retirement of fuel-secure baseload units. PSEG also requested that FERC direct the regional transmission organizations (RTOs) to work with stakeholders to develop a long-term market-based methodology for valuing resiliency in the generator fleet. Additionally, PSEG argued that FERC should expedite the implementation of pending price formation reforms, including fast-start pricing and uplift allocation and market transparency. Finally, PSEG requested that FERC direct PJM to file its proposal that would allow baseload units to set the locational marginal prices during low load conditions. We cannot predict the outcome of this matter.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.

~~Transmission~~

~~In April 2017, the PJM Board announced~~ For additional information about regulatory, legislative and other developments that ~~it would be lifting the previously disclosed suspension of the Artificial Island transmission project~~may affect us, see Part I, Item 1. Business—Regulatory Issues in our Form 10-K and ~~approved the award to PSE&G of the construction of necessary upgrade work at a cost of approximately $130 million. Also,~~Item 5. Other Information in ~~April 2017, PJM submitted a proposal to FERC concerning the cost responsibility assigned to certain entities, including PSE&G,~~our Quarterly Reports on Form 10-Q for the ~~Artificial Island project. In October 2017, FERC accepted PJM’s filing~~periods ending March 31, 2019 and June 30, 2019 (first and second quarter 2019 10-Qs) and this Quarterly Report on the grounds that PJM correctly applied its Tariff, but deferred any further ruling on whether the cost allocation methodology applied to the Artificial Island project is appropriate. FERC will decide this issue in a separate proceeding that is currently pending before it.Form 10-Q.

Transmission Planning

There are several matters pending before FERC ~~and the U. S. Court of Appeals for the District of Columbia Circuit~~ that ~~concern~~may impact the allocation of costs associated with transmission projects, including those being constructed by PSE&G. Regardless of how these proceedings are resolved, PSE&G’s ability to recover the costs of these projects will not be affected. However, the result of these proceedings could ultimately impact the amount of costs borne by ~~ratepayers~~customers in New Jersey. In addition, as a ~~basic generation~~

~~service (BGS)~~BGS supplier, PSEG Power provides services that include specified transmission costs. If the allocation of the costs associated with the transmission projects were to increase these BGS-related transmission costs, BGS suppliers ~~may~~would be entitled to recovery, subject to BPU approval. We do not believe that these matters will have a material effect on PSEG Power’s business or results of operations.

Several complaints have been filed and several remain pending at FERC against transmission owners around the country, challenging those transmission owners’ base return on equity (ROE). Certain of those complaints have resulted in decisions and others have been settled, resulting in reductions of those transmission owners’ base ROEs. The results of these other proceedings could set precedents for other transmission owners with formula rates in place, including PSE&G.

~~Wholesale Power Market Design~~

~~Capacity market design, including the Reliability Pricing Model (RPM) in PJM, remains~~In October 2018, FERC issued an ~~important focus for us. During 2015, PJM implemented~~order establishing a new ~~“Capacity Performance” (CP) mechanism that created~~framework for determining whether a ~~more robust capacity product with enhanced incentives for performance during emergency conditions~~company’s ROE is unjust and ~~significant penalties for non-performance. The CP product was implemented fully in the May 2017 RPM auction for the 2020-2021 Delivery Year. Subsequent~~unreasonable. FERC proposes to ~~its implementation, FERC approved changes~~rely on financial models to ~~the CP construct~~establish a composite zone of reasonableness that will ~~enhance~~be used to determine whether an ROE complaint should be dismissed. If FERC determines that an ROE for a company is not just and reasonable, it intends to reset the participation of intermittent and demand response resources (seasonal resources). However, two complaints remain pending that ask FERC to investigate the rules governing the participation of seasonal resources and extend the participation of the base resources for future auctions.

~~In May 2017, PJM announced~~ROE based on averaging the results of various financial models. We continue to analyze the ~~RPM capacity auction for the 2020-2021 delivery year. Power cleared approximately 7,800 MW~~potential impact of its generating capacity at an average price of $174 per MW-day for the 2020-2021 delivery period. In the two prior capacity auctions covering the 2019-2020 and 2018-2019 delivery years, Power cleared approximately 8,900 MW at an average price of $116 and approximately 8,700 MW at an average price of $215 per MW-day, respectively. Prices in the most recent auction reflect PJM’s downwardly-revised demand forecast, changes in the emergency transfer limits due to transmission expansion and the effects of both the new generation and uncleared generation from the prior year’s auction.

As a result of the efforts of certain entities in PJM to obtain financial support arrangements from their state commissions, a group of suppliers requested that FERC direct PJM to expand the currently effective “minimum offer price rule” to apply to certain existing units seeking subsidies. The suppliers’ request was intended to avoid a scenario where the subsidized generators would submit bids into the PJM capacity market that did not reflect their actual costs of operation and could artificially suppress capacity market prices. We are currently awaiting FERC action on the suppliers’ requestthese methodologies and cannot predict the outcome of ongoing ROE proceedings.

In March 2019, FERC issued two Notices of Inquiry (NOI) that could affect a company’s ROE: (i) an NOI seeking comment on improvements to FERC’s electric transmission incentives policy to ensure that it appropriately encourages the ~~proceeding.~~development of the infrastructure needed to ensure grid reliability and reduce congestion to lower the cost of power for consumers (Incentive NOI), and (ii) an NOI seeking comments whether, and if so how, FERC should change its policies for establishing just and reasonable ROEs. The Incentive NOI is intended to examine whether existing incentives, such as the 50 basis point adder for Regional Transmission Organization membership, should continue to be granted and whether new incentives should be established.

Wholesale Power Market Design

In June ~~2017, PJM~~2018, FERC issued an ~~energy price formation proposal~~order finding that PJM’s current capacity market is not just and reasonable because it enabled state-supported resources to ~~address a flaw~~bid below their costs which resulted in the energy market in which energy prices during off-peak periods often do not reflect the production costs of generators during these periods even though they are serving load. PJM’s proposal would allow large, inflexible units to set price. If placed into effect, this proposal will improve price formation by ensuring that the marginal costs of units serving load will be better reflected insuppressed clearing prices. ~~We cannot predict~~In particular, FERC found that nuclear generating units that receive zero emission certificate payments were of concern. Depending on the outcome of this ~~matter.~~

~~Distribution~~matter, our generating stations could be impacted.

In ~~June 2017,~~late July 2019, FERC issued an order directing PJM to delay its capacity auction until it can approve replacement auction rules and provide greater certainty to the ~~BPU issued proposed Infrastructure Investment Program (IIP) regulations~~market than conducting the auction under existing rules. FERC also denied PJM’s request to clarify that any just and reasonable replacement auction rules ultimately adopted would ~~allow utilities~~operate prospectively. FERC held that it would not rule prematurely on the issue of an appropriate remedy prior to ~~construct, install,~~rendering a determination on the merits of the replacement auction rules. Since one of the Commissioners is recused from this matter, FERC does not have a quorum to issue an order. We do not anticipate an order in this matter until the earlier of either the end of Commissioner Glick’s recusal on November 29, 2019 or ~~remediate utility plant~~when James Danly is confirmed by the Senate and facilities related to reliability, resiliency, and/or safety to support the provision of safe and adequate service. Under the proposed regulations, utilities could seek authority to make specified infrastructure investmentssworn in ~~programs extending for up to five years with accelerated cost recovery mechanisms. The BPU characterized the IIP regulations~~ as a ~~regulatory initiative intended~~Commissioner. We cannot predict when FERC will issue replacement auction rules and what impact those rules will have on the capacity market or our generating stations.

In October 2018, PJM filed with FERC to ~~create a financial incentive for utilities to accelerate~~revise the ~~level~~shape of ~~investment needed to promote~~ the ~~timely rehabilitation and replacement of certain non-revenue producing infrastructure~~Variable Resource Requirement (VRR) curve that ~~enhances reliability, resiliency, and/or safety. The proposed regulations~~ will be ~~subject~~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 ~~comment from interested parties.~~be procured in the auction. PJM’s proposed tariff revisions will result in lower Cost of New Entry 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, which has been delayed until FERC approves new auction rules. In mid-May 2019, PSEG filed a request for rehearing which remains pending before FERC.

Environmental Regulation

We continue to advocate for the development and implementation of fair and reasonable rules by the EPA and state environmental regulators. In particular, section 316(b) of the Federal Water Pollution Control Act requires that cooling water intake structures, which are a significant part of the generation of electricity at steam-electric generating stations, reflect the best technology available for minimizing adverse environmental impacts. Implementation of Section 316(b) and related state regulations could adversely impact future nuclear and fossil operations and costs.

~~In March 2017, the President of the United States issued an Executive Order that instructed the EPA to review the New Source Performance Standards, which establish emissions standards for CO~~₂ for certain new fossil power plants, and the Clean Power Plan (CPP), a greenhouse gas emissions regulation under the Clean Air Act for existing power plants that establishes state-specific emission rate targets based on implementation of the best system of emission reduction. In October 2017, the EPA Administrator signed a proposed repeal of the CPP. The Administrator concluded that the CPP exceeds the EPA’s statutory authority by considering measures that are beyond the control of the owners of the affected sources (fossil fuel-fired electric

generating units). Whether the EPA chooses to propose a replacement rule has not been decided. PSEG cannot estimate the impact of these actions on our business and future results of operations at this time.

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 variousstatutes. 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 1. Note ~~9. Commitments and Contingent Liabilities~~.

~~FERC Compliance~~

Since September 2014, FERC Staff has been conducting a preliminary non-public investigation regarding errors in the calculation of certain components of Power’s cost-based bids for its New Jersey fossil generating units in the PJM energy market and the quantity of energy that Power offered into the energy market for its fossil peaking units compared to the amounts for which Power was compensated in the capacity market for those units. While considerable uncertainty remains as to the final resolution of these matters, based upon developments in the investigation in the first quarter of 2017, Power believes the disgorgement and interest costs related to the cost-based bidding matter may range between approximately $35 million and $135 million, depending on the legal interpretation of the principles under the PJM Tariff, plus penalties. Since no point within this range is more likely than any other, Power has accrued the low end of this range of $35 million by recording an additional pre-tax charge to income of $10 million during the three months ended March 31, 2017. PSEG is unable to reasonably estimate the range of possible loss, if any, for the quantity of energy offered matter or the penalties that FERC would impose relating to either the cost-based bidding or quantity of energy matter. However, any of these amounts could be individually material to PSEG and Power. We cannot predict the final outcome of these matters. For additional information, see Item 1. Note 9.11. Commitments and Contingent Liabilities.

~~Early Retirement~~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 ~~Hudson~~$0.004 per kilowatt-hour (which is equivalent to approximately $10 per megawatt hour (MWh) 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 ~~Mercer Units~~

~~On June 1, 2017,~~will be obligated to maintain operations, subject to exceptions specified in the ZEC legislation. PSEG Power ~~completed its previously announced~~anticipates it will 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 ~~the generation operations~~nuclear plants. The BPU’s decision awarding ZECs has been appealed by Rate Counsel. The financial condition of the ~~existing coal/gas units at~~plants may nonetheless be materially adversely impacted by potential changes to the ~~Hudson~~capacity market construct being considered by FERC (absent sufficient capacity revenues provided under a program approved by the BPU in accordance with a FERC authorized capacity mechanism), and, ~~Mercer generating stations. The decision~~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. Absent a material financial change, these adverse impacts could still result in PSEG Power taking all necessary steps to retire ~~the Hudson and Mercer units had a material effect on PSEG’s and Power’s results~~all of operations in 2016 and continued to adversely impact their results of operations in 2017. As of June 1, 2017, Power completed recognition of the incremental D&A of $938 million ($964 million in total) due to the significant shortening of the expected economic useful lives of Hudson and Mercer. During the first nine months of 2017, Energy Costs of $10 million and O&M of $12 million were also incurred and other costs may be incurred during the remaining period in 2017. See Item 1. Note 3. Early Plant Retirements for additional information.

Power currently anticipates using the sites for alternative industrial activity. However, if Power determines not to use the sites for alternative industrial activity, the early retirement of the units at such sites would trigger obligations under certain environmental regulations, including possible remediation. The amounts for any such remediation are neither currently probable nor estimable but may be material.

~~In addition, PSEG and Power continue to monitor their other coal assets, including the Keystone and Conemaugh generating stations, to assess their economic viability through~~these plants following the end of ~~their designated useful lives and their continued classification as held for use. The precise timing~~the initial three year term of ~~a change~~the ZECs program. Retirement of these plants would result in useful lives may be dependent upon events out of PSEG’s and Power’s control and may impact their ability to operate or maintain certain assets in the future. These generating stations may be impacted by factors such as environmental legislation, co-owner capital requirements and continued depressed wholesale power prices or capacity factors, among other things. Any early retirement or change in the classification as held for use of our remaining coal units may have a material adverse impact on PSEG’s and PSEG Power’s ~~future~~ financial results.

~~Leveraged Lease Portfolio~~Fossil

~~GenOn Energy, Inc. (GenOn),~~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.

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 $56 million as of September 30, 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

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 connection with the Ocean Wind bid, PSEG agreed to provide energy management services and the potential lease of land for use in project development. 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.

Leveraged Leases

In December 2018, NRG REMA, ~~and certain of~~LLC emerged from its ~~subsidiaries filed voluntary petitions for relief~~in-court proceeding under Chapter 11 of the ~~United States~~ Bankruptcy ~~Code on June 14, 2017. REMA was not included in~~Code. As a result of the ~~GenOn bankruptcy filing. GenOn is currently engaged in a balance sheet~~ restructuring, ~~which~~the remaining deferred tax liabilities related to the Keystone and Conemaugh lease investments were reclassified to current tax liabilities. PSEG will ~~take an undetermined time~~realize the remaining tax liability related to ~~complete. Although all lease payments are current, PSEG cannot predict the outcome of GenOn’s efforts to restructure its balance sheet and improve its liquidity. We continue to monitor~~ the restructuring of ~~GenOn and~~approximately $85 million with the ~~possible related impact on REMA and continue to discuss the situation with GenOn.~~

During the first quarter of 2017, due to continuing liquidity issues facing REMA, economic challenges facing coal generation in PJM, and based upon an ongoing review of available alternatives as well as discussions with REMA management, Energy Holdings recorded an additional $55 million pre-tax charge for its current best estimate of loss relating to its REMA leveraged

table of ~~the adverse economic conditions would not lead to additional write-downs at any of our other generation units in our leveraged lease portfolio, and such write-downs could be material.~~contents

lease receivables, which was reflected in Operating Revenues. During the second quarter of 2017, Energy Holdings recorded an additional $22 million pre-tax charge for its current best estimate of loss related to lease receivables due to collectability of payments ($15 million) and economics impacting the residual value ($7 million) of certain leased assets. PSEG continues to monitor any changes to REMA’s and GenOn’s status and potential impacts on Energy Holdings’ lease investments, which could include further write-downsfiling of the ~~values~~consolidated federal income tax return by the end of ~~Energy Holdings’ leveraged lease receivables. For additional information, see Item 1. Note 6. Financing Receivables. There can be no assurance that a continuation or worsening~~2019.

Additional facilities in our leveraged lease portfolio include the Shawville, Joliet and Powerton generating facilities. ~~Similar to Shawville, Joliet was recently converted to use natural gas.~~ 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. 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 Energy Holdings to write down the residual value of the leveraged lease receivables associated with these facilities.

~~Salem~~

~~Concurrently with the planned refueling outage at the Salem 2 unit that was conducted in~~During the second quarter of ~~2017,~~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.

Tax Legislation

The Tax Act, among other things, decreased the statutory U.S. corporate income tax rate from a maximum of 35% to 21%, effective January 1, 2018, and made certain changes to the bonus depreciation and interest disallowance rules.

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 2019, PSEG and PSEG Power expect that a portion of their interest will be disallowed in the current period but realized in future periods. However, certain aspects of the proposed regulations are unclear. Therefore, we ~~inspected~~recorded taxes based on our interpretation of the relevant statute. Amounts recorded under the Tax Act, including but not limited to depreciation and ~~replaced baffle bolts~~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. For additional information, see Item 1. Note 16. Income Taxes.

In September 2019 the IRS released final and additional proposed regulations regarding the application of tax depreciation rules as ~~part~~amended by the Tax Act. We do not believe the final or proposed regulations materially impact our application of the rules.

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. We expect these new provisions to unfavorably affect our ~~strategy~~non-utility business. In accordance with accounting principles generally accepted in the United States for income taxes, deferred taxes are required to ~~replace baffle bolts~~be measured at the ~~Salem station.~~enacted tax rate expected to apply to taxable income in the periods in which the deferred taxes are expected to settle. The ~~unit was returned to service in June 2017.~~

~~Operational Excellence~~

We emphasize operational performance, exercising diligence in managing costs, while developing opportunities in both our competitive and regulated businesses. Flexibility in our generating fleet has allowed us to take advantage of opportunities innewly enacted New Jersey tax legislation did not have a ~~rapidly evolving market. For the first nine months of 2017, our~~

~~utility continued top decile performance in electric reliability,~~

~~total nuclear fleet achieved an average capacity factor of 95%,~~

~~diverse fuel mix and dispatch flexibility allowed us to generate approximately 39 terawatt hours, and~~

~~combined cycle fleet produced 11 terawatt hours at an equivalent availability factor of 94%.~~

~~Financial Strength~~

~~Our financial strength is predicated~~material impact on ~~a solid balance sheet, positive operating cash flow and reasonable risk-adjusted returns on increased investment. Our financial position remained strong during the first nine months of 2017 as we~~

~~maintained sufficient liquidity,~~

~~maintained solid investment grade credit ratings, and~~

~~increased our indicative annual dividend for 2017 to $1.72 per share.~~

~~We expect to be able to fund our planned capital requirements without the issuance of new equity.~~

~~Disciplined Investment~~

We utilize rigorous investment 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, responding to trends in environmental protection and providing new energy supplies in domestic markets with growing demand. In the first nine months of 2017, we

~~made additional investments in transmission infrastructure projects,~~

~~continued to execute our BPU-approved utility programs, and~~

~~continued construction of our Keys and Sewaren 7 generation projects for targeted commercial operation in 2018 and began construction of BH5 for targeted commercial operations in mid-2019.~~PSEG’s deferred income tax balance.

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 and public policy.

Our future success will depend on our ability to continue to maintain strong operational and financial performance in ~~a cost-constrained~~an environment with low gas prices, to capitalize on or otherwise address ~~appropriately~~ regulatory and legislative

table of ~~our Keys, Sewaren 7, BH5 and other generation projects,~~contents

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 ~~reliability~~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,

~~successfully launch~~obtain approval of and ~~grow our retail energy business, which complements our existing wholesale energy business,~~

execute our utility capital investment program, including ES II, GSMP II, our ~~Energy Strong~~CEF program ~~GSMP~~and transmission and other investments ~~for growth~~ 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,

~~effectively manage construction and start-up~~

advocate for the continuation of the ZEC program and measures to ensure the implementation by PJM and FERC 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.

~~For 2017~~In addition to the risks described elsewhere in this Form 10-Q, the first and second quarter 2019 10-Qs and in our Form 10-K, for 2019 and beyond, the key issues ~~challenges~~ and ~~opportunities~~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 ~~proceeding, settlement, investigation or claim, applicable to us and/or the energy industry,~~

~~fair and timely rate relief from the BPU and FERC for recovery of costs and return on investments, including with respect to our distribution base rate case proceeding to be filed in 2017,~~proceedings,

the ~~potential for comprehensive tax reform, particularly in light~~continuing impacts of ~~public statements by~~ the ~~current U.S. administration~~Tax Act and ~~key members of Congress,~~

~~uncertainty in the national and regional economic performance, continuing customer conservation efforts,~~ changes in ~~energy usage patterns~~state tax laws, and ~~evolving technologies, which impact customer behaviors and demand,~~

the ~~potential for continued~~impact of reductions in demand and ~~sustained~~ lower natural gas and electricity prices ~~both at market hubs and the locations where we operate,~~

~~the impact of lower natural gas prices~~ and increasing environmental compliance ~~costs on the competitiveness of our nuclear and remaining coal-fired generation plants, and the potential for retirement of such plants earlier than their current useful lives,~~costs.

~~ensuring timely completion of construction of our T&D, generation and other development projects, including obtaining required permits and regulatory approvals,~~

~~maintaining a diverse mix of fuels to mitigate risks associated with fuel price volatility and market demand cycles, and~~

~~FERC Staff’s continuing investigation of certain of Power’s New Jersey fossil generating unit bids in the PJM energy market.~~

~~Our primary investment opportunities are in two areas: our regulated utility business and our merchant power business.~~ 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 ~~transmission and distribution~~T&D facilities, clean energy investments and/or generation ~~units,~~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,

~~Table~~ including the operation of ~~Contents~~

~~continued or expanded participation in solar, energy efficiency and related programs,~~T&D facilities outside of our traditional service territory, 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

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 1. Note ~~18.~~20. Related-Party Transactions.

Three Months Ended
Increase/
(Decrease)
Nine Months Ended
Increase/
(Decrease)

September 30, September 30,
2017 2016 2017 vs. 2016 2017 2016 2017 vs. 2016
Millions Millions % Millions Millions %
Operating Revenues $ 2,263
$ 2,450
$ (187 ) (8 ) $ 6,988
$ 6,971
$ 17
—

Energy Costs 638
866
(228 ) (26 ) 2,100
2,326
(226 ) (10 )
Operation and Maintenance 680
776
(96 ) (12 ) 2,100
2,215
(115 ) (5 )
Depreciation and Amortization 252
231
21
9
1,721
679
1,042
N/A

Income from Equity Method Investments 3
3
—
—
11
9
2
22

Other Income (Deductions) 56
39
17
44
178
100
78
78

Other-Than-Temporary Impairments 5
5
—
—
9
25
(16 ) (64 )
Interest Expense 100
99
1
1
289
288
1
—

Income Tax Expense 252
188
64
34
340
562
(222 ) (40 )




	Three Months Ended					Increase/ (Decrease)					Nine Months Ended				Increase/ (Decrease)
	September 30,					Increase/ (Decrease)					September 30,				Increase/ (Decrease)
	2019			2018		2019 vs. 2018					2019		2018		2019 vs. 2018
	Millions					Millions			%		Millions				Millions			%
Operating Revenues	$	2,302		$	2,394	$	(92	)	(4	)	$	7,598	$	7,228	$	370		5
Energy Costs	753			804		(51		)	(6	)	2,581		2,356		225			10
Operation and Maintenance	745			742		3			—		2,251		2,221		30			1
Depreciation and Amortization	307			294		13			4		928		854		74			9
Loss on Asset Dispositions	7			—		7			N/A		402		—		402			N/A
Income from Equity Method Investments	3			5		(2		)	(40	)	10		12		(2		)	(17	)
Net Gains (Losses) on Trust Investments	(3		)	45		(48		)	N/A		164		31		133			N/A
Other Income (Deductions)	35			33		2			6		101		99		2			2
Non-Operating Pension and OPEB Credits (Costs)	55			19		36			N/A		121		57		64			N/A
Interest Expense	147			127		20			16		417		341		76			22
Income Tax (Benefit) Expense	30			117		(87		)	(74	)	159		416		(257		)	(62	)

The following discussions for PSE&G and PSEG Power provide a detailed explanation of their respective variances.

PSE&G

Three Months Ended
Increase/
(Decrease)
Nine Months Ended
Increase/
(Decrease)

September 30, September 30,
2017 2016 2017 vs. 2016 2017 2016 2017 vs. 2016
Millions Millions % Millions Millions %
Operating Revenues $ 1,509
$ 1,684
$ (175 ) (10 ) $ 4,689
$ 4,746
$ (57 ) (1 )
Energy Costs 535
721
(186 ) (26 ) 1,760
1,979
(219 ) (11 )
Operation and Maintenance 346
376
(30 ) (8 ) 1,064
1,110
(46 ) (4 )
Depreciation and Amortization 169
137
32
23
506
412
94
23

Other Income (Deductions) 22
21
1
5
67
58
9
16

Interest Expense 79
72
7
10
223
214
9
4

Income Tax Expense 156
144
12
8
450
393
57
15




	Three Months Ended				Increase/ (Decrease)					Nine Months Ended				Increase/ (Decrease)
	September 30,				Increase/ (Decrease)					September 30,				Increase/ (Decrease)
	2019		2018		2019 vs. 2018					2019		2018		2019 vs. 2018
	Millions				Millions			%		Millions				Millions			%
Operating Revenues	$	1,604	$	1,595	$	9		1		$	5,018	$	4,826	$	192		4
Energy Costs	618		593		25			4		2,094		1,863		231			12
Operation and Maintenance	388		389		(1		)	—		1,165		1,133		32			3
Depreciation and Amortization	206		192		14			7		620		569		51			9
Net Gains (Losses) on Trust Investments	—		—		—			—		1		—		1			N/A
Other Income (Deductions)	22		21		1			5		60		61		(1		)	(2	)
Non-Operating Pension and OPEB Credits (Costs)	46		14		32			N/A		105		44		61			N/A
Interest Expense	92		83		9			11		268		246		22			9
Income Tax Expense (Benefit)	24		95		(71		)	(75	)	63		292		(229		)	(78	)

Three Months Ended September 30, ~~2017~~2019 as Compared to ~~2016~~2018

Operating Revenues ~~decreased $175~~ increased $9 million due to changes in delivery, commodity, clause and other operating revenues.

~~Table~~table of ~~Contents~~contents

Delivery Revenues increased ~~$10~~$8 million due to


•	Transmission revenues were $32 million higher due to increased 2019 revenue requirements primarily attributable to higher rate base investment.


•	Electric distribution revenues increased $26 million due to a $26 million increase resulting from the favorable impact of the distribution base rate tariff and a $6 million increase in Green Program Recovery Charge (GPRC) revenues, partially offset by a $6 million decrease due to lower sales volumes.


•	Gas distribution revenues increased $22 million due primarily to a $19 million increase from the favorable impact of the distribution base rate tariff effective November 2018 and a $2 million increase in revenues from GSMP I.


•	Gas, Electric and Transmission revenue requirements were reduced by $72 million due to the flowback of excess deferred tax liabilities and tax repair-related accumulated deferred income tax benefits as a result of settlements with the BPU and FERC. This reduction is offset in Income Tax Expense.

Commodity Revenues decreased$23 million as a result of lower Electric revenues, partly offset by higher Gas revenues. The changes in Commodity revenues for both electric and gas are entirely offset by changes in Energy Costs. PSE&G earns no margin on the provision of BGS and basic gas supply service (BGSS) to retail customers.


•	Electric commodity revenues decreased$26 million due primarily to a $205 million decrease in BGS prices, partially offset by $178 million in higher sales volumes.


•	Gas commodity revenues increased$3 million due primarily to higher BGSS prices.

Clause Revenuesdecreased$31 million due primarily to $22 million of lower Tax Adjustment Credit (TAC) deferrals, a $5 million reduction in GPRC deferrals and lower Societal Benefit Charge (SBC) revenues of $3 million. The changes in TAC and GPRC deferrals and SBC revenues are entirely offset by changes in the amortization of Regulatory Assets and Regulatory Liabilities and related costs in O&M, D&A and Interest Expenses. PSE&G does not earn margin on TAC or GPRC deferrals or on SBC revenues.

Other Operating Revenues increased$55 million due primarily to ZEC revenues billed after the ZEC program was approved by the BPU in April 2019. See Item 1. Note 11. Commitments and Contingent Liabilities. These revenues are entirely offset by changes to Energy Costs.

Operating Expenses

Energy Costs increased $25 million. This is entirely offset by changes in Commodity Revenues and Other Operating Revenues.

Operation and Maintenance decreased $1 million due primarily to a $5 million reduction in distribution preventative and corrective maintenance expenditures, a $3 million reduction in transmission expenditures, a $3 million decrease in injuries and damages and a $5 million net reduction in other operating expenses. These decreases were partially offset by a net $11 millionincrease in clause and renewable-related expenditures and a $5 million increase in storm costs.

Depreciation and Amortization increased $14 million due primarily to additional plant and software placed into service.

Non-Operating Pension and OPEB Credits (Costs) increased $32 million due primarily toa $26 million increase in the amortization of the prior service credit mainly related to the December 2018 OPEB plan amendment, a $4 million decrease in interest cost and a $3 million decrease in the amortization of the net unrecognized loss, partially offset by a reduction of $2 million in the long-term expected return on plan assets.

Interest Expense increased $9 million due primarily to increases of $7 million from net debt issuances in the second and third quarters of 2019 and $2 million from net debt issuances in 2018.

Income Tax Expense decreased $71 million due primarily to the flowback to ratepayers of excess deferred income tax liabilities and tax repair-related accumulated deferred income taxes.

Nine Months Ended September 30, 2019 as Compared to 2018

Operating Revenues increased $192 million due to changes in delivery, commodity, clause and other operating revenues.

Delivery Revenues decreased $30 million due primarily to

Gas, Electric and Transmission revenue requirements were reduced by $277 million due to the flowback of excess deferred tax liabilities and tax repair-related accumulated deferred income tax benefits as a result of settlements with the BPU and FERC. This reduction is offset in Income Tax Expense.

Gas distribution revenues increased $92 million due primarily to an $89 million increase ~~in transmission revenues.~~from the favorable impact of the distribution base rate tariff effective November 2018.

Transmission revenues were ~~$34~~$90 million higher due to ~~higher~~increased 2019 revenue requirements ~~calculated through our transmission formula~~primarily attributable to higher rate ~~primarily to recover required investments.~~base investment.

~~Gas~~Electric distribution revenues increased $5$65 million due to a $1$67 million increase resulting from the ~~inclusion~~favorable impact of ~~Energy Strong~~the distribution base rate tariff and a $14 million increase in ~~base rates, and $1 million~~GPRC revenues. These increases ~~in both GSMP collections and Green Program Recovery Charges (GPRC) and higher sales volumes.~~

~~Electric distribution revenues decreased $29 million due to~~were partially offset by a ~~$38~~$16 million decrease due to lower sales ~~volumes and lower GPRC of $6 million, partially offset by a $15 million increase from the inclusion of Energy Strong in base rates.~~volumes.

Commodity ~~Revenue~~ ~~decreased $186~~Revenues increased $153 million as a result of ~~lower~~higher Gas and Electric ~~and Gas~~ revenues. The changes in Commodity ~~revenue~~revenues for both ~~electric~~gas and ~~gas~~electric are entirely offset by the changes in Energy Costs. PSE&G earns no margin on the provision of ~~BGS~~BGSS and ~~BGSS~~BGS to retail customers.

Gas commodity revenues increased $129 million due to higher BGSS prices of $106 million and higher BGSS sales volumes of $23 million.

Electric commodity revenues increased $24 million due primarily to $47 million in higher BGS sales volumes, partially offset by $24 million in lower BGS prices.

Clause Revenuesdecreased ~~$176~~$11 million due primarily to a ~~$153~~$15 million ~~decrease in BGS revenues due to $97 million in lower sales volumes and $56 million from lower prices and $23 million of lower revenues from collections of Non-Utility Generation Charges (NGC).~~

~~Gas commodity revenues decreased $10 million due to lower BGSS sales prices of $22 million, partially offset by higher BGSS sales volumes of $12 million.~~

~~Clause Revenues~~ increased $1 million due primarily to the return of $20 million to customers in 2016 of overcollections of Securitization Transition Charges (STC), partially offset by lower Societal Benefit Charges (SBC) of $12 millionreduction for TAC deferrals and a $6 million decrease ~~in 2017~~for GPRC deferrals. These decreases were partially offset by a $7 million increase in Margin Adjustment Clause (MAC) ~~revenues.~~revenues, a $2 million increase in Solar Pilot Recovery Charges (SPRC) and higher SBC revenues of $1 million. The changes in the ~~STC,~~MAC, SPRC and SBC revenues and ~~MAC~~TAC and GPRC deferral amounts are entirely offset by changes in the amortization of Regulatory Assets and Regulatory Liabilities and related costs in O&M, D&A and Interest ~~Expense.~~Expenses. PSE&G does not earn margin on ~~STC,~~MAC, SPRC or SBC revenues or ~~MAC collections.~~on TAC or GPRC deferrals.

Other Operating Revenues increased by $80 million due primarily to ZEC revenues billed since mid-April 2019. See Item 1. Note 11. Commitments and Contingent Liabilities. These revenues are entirely offset by changes to Energy Costs.

Operating Expenses

Energy Costs ~~decreased $186~~ increased $231 million. This is entirely offset by ~~the change~~changes in Commodity ~~Revenue.~~Revenues and Other Operating Revenues.

Operation and Maintenance decreased $30 million, primarily due to a $17 million reduction in clause-related costs, $6 million in lower appliance service costs, $6 million of lower distribution corrective and preventative maintenance and a $5 million reduction in GPRC related costs, partially offset by a net increase of $4 million in certain operational expenses.

~~Depreciation and Amortization~~ increased $32 million due primarily to ~~an increase of $19 million in amortization of Regulatory Assets and~~ a ~~$14~~net $45 million increase in ~~depreciation due to additional plant in service.~~

~~Interest Expense~~ ~~increased $7 million due primarily to an increase of $5 million due to net debt issuances in 2016~~clause and ~~2017~~renewable-related expenditures and a $2$4 million increase in ~~other interest.~~injuries and damages. These increases were partially offset by an $8 million decrease in distribution preventative and corrective maintenance expenditures, a $6 million reduction in seasonal storm costs and a $1 million decrease in transmission-related expenditures.

~~Income Tax Expense~~Depreciation and Amortization increased ~~$12 million due primarily to uncertain tax positions and plant-related items.~~

~~Nine Months Ended September 30, 2017 as Compared to 2016~~

~~Operating Revenues~~ ~~decreased $57 million due to changes in delivery, commodity, clause and other operating revenues.~~

~~Delivery Revenues~~ ~~increased $119 million due primarily to an increase in transmission revenues.~~

~~Transmission revenues were $116 million higher due to higher revenue requirements calculated through our transmission formula rate, primarily to recover required investments.~~

~~Gas distribution revenues increased $29~~$51 million due to a ~~$14~~$44 million increase ~~due~~related to ~~the inclusion of Energy Strong in base rates, $8 million in higher Weather Normalization Clause (WNC) revenue,~~additional plant and software placed into service and a $7 million increase due to updated depreciation rates put into effect in November 2018.

Non-Operating Pension and OPEB Credits (Costs) increased $61 milliondue primarilyto a $77 million increase in the ~~GSMP~~amortization of prior service credit mainly related to the December 2018 OPEB plan amendment and ~~higher GPRC of~~a $3 million ~~partially offset by $3 million of lower delivery volumes.~~

~~Electric distribution revenues decreased $26 million due to a $36 million~~ decrease ~~due to lower sales volumes and lower GPRC of $14 million,~~in interest cost, partially offset by a ~~$24~~$16 million reduction in the long-term expected return on plan assets and a $4 million increase ~~due to~~in the ~~inclusion~~amortization of ~~Energy Strong in base rates.~~the net unrecognized loss.

~~Commodity Revenue~~ decreased $219 million as a result of lower Electric revenues partially offset by higher Gas revenues. The changes in Commodity revenue for both electric and gas are entirely offset by the changes in Energy Costs. PSE&G earns no margin on the provision of BGS and BGSS to retail customers.

~~Electric commodity revenues decreased $266~~Interest Expense increased $22 million due primarily to a ~~$188~~$12 million ~~decrease~~increase from net debt issuances in ~~BGS revenues due to $116 million in lower sales volumes~~May and ~~$72 million of lower prices, $64 million of lower revenues from collections of NGC~~September 2018 and a ~~decrease of $14~~$10 million ~~due to lower volumes of Non-Utility Generation energy sold.~~increase from net debt issuances in 2019.

~~Gas commodity revenues increased $47 million due primarily to $69 million of higher BGSS sales prices, partially offset by $22 million of lower sales volumes.~~

~~Clause Revenues~~ ~~increased $41~~Income Tax Expense decreased $229 million due primarily to the ~~2016 return~~flowback to ~~customers~~ratepayers of ~~$50 million of overcollections of STC,~~excess deferred income tax liabilities and higher MAC revenues of $2 million in 2017, partially offset by a $12 million decrease in collections of SBC. The changes in the STC, MAC and SBC amounts are entirely offset by changes in the amortization of Regulatory Assets and Regulatory Liabilities and related costs in O&M, D&A and Interest Expense. PSE&G does not earn margin on STC, MAC or SBC collections.tax repair-related accumulated deferred income taxes.

~~Operating Expenses~~

~~Energy Costs~~ ~~decreased $219 million. This is entirely offset by the change in Commodity Revenue.~~

~~Operation and Maintenance~~ decreased $46 million, of which the most significant components were decreases of $17 million in distribution corrective and preventative maintenance, $14 million in appliance service costs, $11 million in clause-related costs and $11 million in GPRC costs, partially offset by a $10 million net increase in certain operational expenses.

~~Depreciation and Amortization~~ ~~increased $94 million due primarily to an increase of $51 million in amortization of Regulatory Assets and a $43 million increase in depreciation due to additional plant in service.~~

~~Other Income and (Deductions)~~ increased $9 million due primarily to an increase of $7 million in allowance for funds used during construction and a $3 million increase in realized gains on Rabbi Trust investments, partially offset by a net $1 million decrease in Solar Loan interest.

~~Interest Expense~~ increased $9 million due primarily to an increase of $16 million due to net debt issuances in 2016 and 2017, partially offset by a $7 million decrease predominantly driven by a reduction in clause interest.

~~Income Tax Expense~~ ~~increased $57 million due primarily to higher pre-tax income and changes in uncertain tax positions.~~

PSEG Power




	Three Months Ended					Increase/ (Decrease)					Nine Months Ended				Increase/ (Decrease)
	September 30,					Increase/ (Decrease)					September 30,				Increase/ (Decrease)
	2019			2018		2019 vs. 2018					2019		2018		2019 vs. 2018
	Millions					Millions			%		Millions				Millions			%
Operating Revenues	$	771		$	868	$	(97	)	(11	)	$	3,270	$	3,038	$	232		8
Energy Costs	359			431		(72		)	(17	)	1,556		1,550		6			—
Operation and Maintenance	233			231		2			1		736		745		(9		)	(1	)
Depreciation and Amortization	93			94		(1		)	(1	)	282		260		22			8
Loss on Asset Dispositions	7			—		7			N/A		402		—		402			N/A
Income from Equity Method Investments	3			5		(2		)	(40	)	10		12		(2		)	(17	)
Net Gains (Losses) on Trust Investments	(4		)	44		(48		)	N/A		160		30		130			N/A
Other Income (Deductions)	15			14		1			7		43		38		5			13
Non-Operating Pension and OPEB Credits (Costs)	8			4		4			100		14		11		3			27
Interest Expense	34			29		5			17		85		47		38			81
Income Tax Expense (Benefit)	14			25		(11		)	(44	)	127		127		—			—

Three Months Ended
Increase/
(Decrease)
Nine Months Ended
Increase/
(Decrease)

September 30, September 30,
2017 2016
2017 vs. 2016 2017 2016 2017 vs. 2016
Millions Millions % Millions Millions %
Operating Revenues $ 873
$ 1,075
$ (202 ) (19 ) $ 3,086
$ 3,102
$ (16 ) (1 )
Energy Costs 357
462
(105 ) (23 ) 1,461
1,481
(20 ) (1 )
Operation and Maintenance 227
289
(62 ) (21 ) 711
807
(96 ) (12 )
Depreciation and Amortization 76
86
(10 ) (12 ) 1,191
245
946
N/A

Income from Equity Method Investments 3
3
—
—
11
9
2
22

Other Income (Deductions) 35
17
18
N/A
105
41
64
N/A

Other-Than-Temporary Impairments 5
5
—
—
9
25
(16 ) (64 )
Interest Expense 12
24
(12 ) (50 ) 41
66
(25 ) (38 )
Income Tax Expense (Benefit) 98
90
8
9
(80 ) 208
(288 ) N/A

Three Months Ended September 30, ~~2017~~2019 as Compared to ~~2016~~2018

Operating Revenues decreased ~~$202~~$97 million due primarily to changes in generation and gas supply revenues.

Generation Revenues decreased ~~$200~~$59 million due primarily to

a net decrease of $50 million due primarily to lower volumes of electricity sold in the PJM and New York (NY) regions, coupled with lower average realized prices in the PJM, NY, and New England (NE) regions, partially offset by higher volumes of electricity sold in the NE region,

a decrease of $110 million due to MTM losses in 2017 as compared to MTM gains in 2016. Of this amount, $98 million was due to changes in forward prices and $12 million was due to greater gains on positions reclassified to realized upon settlement this year as compared to last year,

~~a decrease of $83~~$25 million in electricity sold under our BGS contracts primarily due to lower volumes ~~and~~coupled with lower prices,

a net decrease of $20 million due to higher MTM losses in 2019 as compared to 2018. Of this amount, there was a $57 million decrease due to more losses on positions reclassified to realized upon settlement, partially offset by a $37 million increase from changes in forward prices in 2019 as compared to 2018, and

a net decrease of ~~$25~~$19 million in ~~energy sales~~capacity revenues due primarily to decreases in auction prices for cleared capacity in the PJM region, partially offset by increased capacity payments in the NE region due to BH5 beginning commercial operations in June 2019,

partially offset by an increase of $51 million due to ZEC revenues earned since mid-April 2019.

Gas Supply Revenues decreased $39 million due primarily to

a net decrease of $45 million related to sales to third parties, of which $48 million was due to lower ~~generation~~ volumes ~~and lower~~sold, modestly offset by a $3 million increase due to higher average ~~realized~~sales prices,

partially offset by a net increase of ~~$18~~$5 million in sales under the BGSS contract, of which $3 million was due ~~primarily~~ to higher ~~capacity revenue~~sales volumes and ~~electricity sold under wholesale load contracts at~~$2 million to higher average sales prices ~~coupled with new solar projects.~~

~~Gas Supply Revenues~~ ~~decreased $2 million due to lower MTM gains in 2017 as compared to 2016.~~during 2019.

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 ~~$105~~$72 million due to

Generation costs decreased ~~$108~~$39 million due primarily to

a net decrease of $59 million due to charges associated with the early retirement of the Mercer and Hudson units announced in October 2016, primarily related to a coal inventory write-down, partially offset by additional retirement costs incurred in 2017,

~~a net decrease of $26 million due primarily to lower natural gas costs reflecting lower volumes,~~

~~a net decrease of $11 million primarily due to lower congestion costs in PJM due to lower congestion rates coupled with less congestion volumes, and~~

~~a decrease of $8~~$30 million due to MTM gains in ~~2017~~2019, as compared to MTM losses in ~~2016.~~2018, due primarily to positions reclassified as realized upon settlement, and

a net decrease of $10 million primarily due to decreases in energy purchases in the NE region due to BH5 beginning commercial operations in June 2019.

Gas costs ~~increased $3~~ decreased $33 million due ~~mainly~~primarily to

a ~~net increase~~decrease of $2$42 million related to sales to third parties due primarily to lower volumes sold,

partially offset by a net increase of $10 million related to sales under the BGSS contract, of which $5 million was due to higher volumes and $5 million to higher average gas ~~costs,~~costs.

Depreciation and Amortization decreased$1 million due primarily to the sale of PSEG Power’s ownership interests in the Keystone and Conemaugh generation plants, largely offset by the BH5 station being placed into service in June 2019.

Net Gains (Losses) on Trust Investments decreased $48 million due primarily to a $55 million decrease resulting from net unrealized losses in 2019 as compared to net unrealized gains in 2018 on equity investments in the NDT Fund, partially offset by $3a $6 million increase in net realized gains on NDT Fund investments.

Non-Operating Pension and OPEB Credits (Costs) increased $4 million due to ~~lower volumes sold.~~

~~Operation and Maintenance~~ ~~decreased $62~~a $5 million ~~due primarily~~increase in the amortization of prior service credit mainly related to

the December 2018 OPEB plan amendment, a ~~$51~~$2 million decrease ~~at our fossil plants, due to~~in the ~~retirement~~amortization of the ~~Hudson~~net unrecognized loss and ~~Mercer units~~a $1 million decrease in interest cost, largely offset by a $4 million reduction in the long-term expected return on ~~June 1, 2017, and~~plan assets.

~~a $10~~Interest Expense increased $5 million ~~net decrease related to our nuclear plants~~ due primarily to lower ~~labor-related costs.~~

~~Depreciation and Amortization~~ ~~decreased$10 milliondue primarily to~~

~~$19 million~~capitalized interest as a result of ~~lower depreciation due to the retirement of the Hudson and Mercer units,~~

~~partially offset by $4 million of increased depreciation due to the accelerated retirement date at Bridgeport Harbor Station unit 3 (BH3),~~

~~$3 million of higher depreciation due to new solar projects, and~~

~~a $2 million increase due to additional nuclear plant~~BH5 being placed into ~~service.~~service in June 2019.

~~Other~~ Income ~~(Deductions)~~ ~~increased $18~~Tax Expense (Benefit) decreased $11 million due primarily to ~~higher net realized gains in the NDT Fund.~~

~~Interest Expense~~ ~~decreased $12 million due primarily to~~

~~a $7 million decrease due to higher interest capitalized for the construction of three new fossil stations: BH5, Sewaren 7 and Keys, and~~

~~a $5 million decrease due to debt maturities in September 2016.~~

~~Income Tax Expense (Benefit)~~ ~~reflected anincreased tax expense of $8 million due primarily to changes in the manufacturing deduction and higher~~lower pre-tax income in ~~2017.~~2019, partially offset by benefits associated with the remeasurement of uncertain tax positions recorded in 2018.

Nine Months Ended September 30, ~~2017~~2019 as Compared to ~~2016~~2018

Operating Revenues~~decreased$16~~ increased $232 million due primarily to changes in generation and gas supply revenues.

Generation Revenues ~~decreased $101~~ increased $277 million due primarily to

a net ~~decrease~~increase of ~~$115~~$272 million due to MTM gains in 2019 as compared to MTM losses in 2018. Of this amount, there was a $268 million increase from changes in forward prices in 2019 as compared to 2018, coupled with a $4 million increase due to more gains on positions reclassified to realized upon settlement,

an increase of $85 million due to ZEC revenues earned since mid-April 2019,

a net increase of $12 million in ~~energy sales~~capacity revenues due primarily to the commencement of commercial operations of Keys and Sewaren 7 in in mid-2018 and BH5 in June 2019, partially offset by a decrease in auction prices in the PJM region, and

a net increase of $5 million due primarily to higher volumes of electricity sold in the PJM and ~~New England~~NE regions, ~~due primarily to~~somewhat offset by lower volumes sold in the NY region and lower average realized prices in the PJM, NE and NY regions,

partially offset by a decrease of ~~$91~~$93 million in electricity sold under our BGS contracts due to lower volumes and lower ~~prices,~~prices.

Gas Supply Revenuesdecreased $47 million due primarily to

a ~~net~~ decrease of ~~$11~~$93 million ~~in operating reserves in the PJM region, and~~

~~a charge of $10 million~~related to sales to third parties, primarily due to ~~an increase in the FERC reserve accrual related to the PJM bidding matter see Item 1. Note 9. Commitments and Contingent Liabilities,~~

lower volumes sold,

partially offset by an increase of $86 million due to lower MTM losses in 2017 as compared to 2016. Of this amount, $110 million was due to lower gains on positions reclassified to realized upon settlement this year as compared to last year partially offset by a decrease of $24 million due to changes in forward power prices.

~~a net increase of $31 million due primarily to higher volumes of electricity sold under wholesale load contracts in the NE region, and~~

~~an increase of $10 million due to new solar projects.~~

~~Gas Supply Revenuesincreased~~ ~~$84 million due primarily to~~

~~an increase of $45~~$41 million in sales under the BGSS contract, ~~due~~ primarily ~~to higher average sales prices,~~

~~an increase of $25 million related to sales to third parties, of which $52 million was~~ due to higher average sales ~~prices, partially offset by $27 million of lower volumes sold, and~~

~~a net increase of $14 million due to MTM gains in 2017 as compared to MTM losses in 2016.~~prices.

Operating Expenses

Generation costs ~~decreased $76~~ increased $33 million due primarily to higher fuel costs reflecting utilization of higher volumes of gas at the new Keys and Sewaren 7 fossil stations and BH5, coupled with higher prices of gas in the PJM region, partially offset by

utilization of lower volumes and 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 coal costs in the PJM and NE regions.

Gas costsdecreased $27 million due mainly to

a net decrease of ~~$57~~$76 million related to sales to third parties due primarily ~~due~~ to lower ~~congestion costs in PJM due to lower congestion rates coupled with less congestion~~ volumes ~~partially offset by higher transmission charges due to higher rates,~~

a net decrease of $49 million due to charges associated with the announced early retirement of the Mercer and Hudson units in 2016, primarily related to a coal inventory write-down partially offset by additional retirement costs incurred in 2016,sold,

partially offset by higher fuel costs of $12 million reflecting higher average realized prices for natural gas coupled with the utilization of higher volumes of coal, partially offset by the utilization of lower volumes of gas and oil,

a net increase of ~~$10 million primarily due to an increase in energy purchase volumes in the NE region to serve load obligations, and~~

~~an increase of $9 million due to MTM losses in 2017 as compared to MTM gains in 2016.~~

~~Gas costsincreased~~ ~~$56 million due mainly to~~

~~an increase of $32~~$51 million related to sales under the BGSS contract ~~due to higher average gas costs, and~~

primarily resulting from an increase in the average cost of ~~$24 million related to sales to third parties, of which $48 million was due to higher average gas costs, partially offset by a $24 million decrease in volumes sold.~~gas.

Operation and Maintenance decreased ~~$96~~$9 million due primarily to

a ~~$71 million decrease at our fossil plants, due primarily to the retirement of the Hudson and Mercer units and higher planned outage costs in 2016 as compared to 2017,~~

~~a $20 million~~ net decrease related to our nuclear plants due to planned outage costs incurred in 2019 for our 57%-owned Salem Unit 1 as compared to planned outage costs at our 100%-owned Hope Creek nuclear plant in 2018.

Depreciation and Amortization increased$22 milliondue primarily to ~~lower labor-related costs~~the new Keys and ~~outage costs,~~Sewaren 7 fossil stations and

~~an $8 million legal accrual for environmental expenses recorded in 2016,~~

BH5 station, partially offset by $3the sale of PSEG Power’s ownership interests in the Keystone and Conemaugh generation plants.

Loss on Asset Dispositions isa$402 million ~~of costs~~loss in 2019 related to ~~new solar plants placed into service since September 2016.~~the sale of PSEG Power’s ownership interests in the Keystone and Conemaugh generation plants.

~~Depreciation and Amortization~~ ~~increased$946 milliondue primarily to~~

~~$914 million of higher depreciation due to the early retirement of the Hudson and Mercer units,~~

~~$11 million of~~ Net Gains (Losses) on Trust Investments increased ~~depreciation due to the accelerated retirement date at BH3,~~

~~$9 million of higher depreciation due to new solar projects, and~~

~~a $9 million increase due to additional nuclear plant placed into service.~~

~~Other Income (Deductions)~~ ~~increased $64~~$130 million due primarily to ~~$57~~a $127 million ~~of higher~~increase resulting from net ~~realized~~unrealized gains in 2019 as compared to net unrealized losses in 2018 on equity investments in the NDT Fund.

Other Income (Deductions) increased $5 million primarily due to higher interest and dividend income on NDT Fund investments.

Non-Operating Pension and OPEB Credits (Costs) increased $3 ~~million of higher net realized gains in the Rabbi Trust Fund.~~

~~Other-Than-Temporary Impairments~~ ~~decreased $16~~ million due to ~~lower impairments of equity securities~~a $14 million increase in the ~~NDT Fund~~amortization of prior service credit mainly related to the December 2018 OPEB plan amendment, a $4 million decrease in ~~2017.~~

~~Interest Expense~~ ~~decreased $25~~interest cost and a $1 million ~~due primarily to~~

decrease in the amortization of the net unrecognized loss, largely offset by a $16 million decrease ~~due to higher interest capitalized for~~in the ~~construction of three new fossil stations: BH5, Sewaren 7 and Keys, and~~long-term expected return on plan assets.

~~a net $7~~Interest Expense increased $38 million ~~decrease due to debt maturities in September 2016, partially offset by a debt issuance in June 2016.~~

~~Income Tax Expense (Benefit)~~ ~~decreased $288 million in 2017~~ due primarily to lower capitalized interest as a ~~pre-tax loss~~result of Keys and Sewaren 7 fossil stations being placed into service in ~~2017 as compared to pre-tax income in 2016.~~mid-2018.

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.

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 nine months ended September 30, ~~2017~~2019, our operating cash flow ~~decreased~~increased$27217 million as compared to the same period in ~~2016.~~2018. The net ~~change was~~changes were primarily due ~~primarily~~ to the net changes from ~~PSE&G and Power~~our subsidiaries as discussed below, ~~as well as net~~partially offset by tax payments at PSEG and its other ~~subsidiaries.~~subsidiaries in 2019 compared to tax refunds in 2018.

PSE&G

PSE&G’s operating cash flow ~~decreased~~increased$884 million from $~~1,401~~1,397 million to $~~1,393~~1,481 million for the nine months ended September 30, ~~2017~~2019, as compared to the same period in ~~2016~~2018, due primarily to ~~lower~~ tax refunds in 2019 as compared to tax payments in 2018, and ~~a decrease~~an increase of ~~$49~~$89 million ~~due to~~from a change in regulatory deferrals, partially offset by ~~higher earnings.~~a decrease of $79 million relating to a lower reduction in accounts receivable and unbilled revenues in 2019, and $70 million in increased vendor payments.

PSEG Power

PSEG Power’s operating cash flow ~~decreased$11~~increased $357 million from ~~$1,260~~$1,005 million to ~~$1,249~~$1,362 million for the nine months ended September 30, ~~2017~~,2019, as compared to the same period in ~~2016,~~2018, due ~~primarily~~ to ~~tax payments in 2017 as compared to tax refunds in 2016 and lower earnings, partially offset by~~ a ~~$68~~$378 million ~~decrease~~higher reduction in margin deposit requirements, and ~~a $30~~tax refunds in 2019 compared to tax payments in 2018, partially offset by an increase of $40 million ~~increase from net collection of counterparty receivables.~~in payments to counterparties.

Short-Term Liquidity

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 September 30, ~~2017~~2019 were as follows:

Company/Facility As of September 30, 2017

Total
Facility
Usage
Available
Liquidity

Millions
PSEG $ 1,500
$ 215
$ 1,285

PSE&G 600
15
585

Power 2,100
182
1,918

Total $ 4,200
$ 412
$ 3,788




Company/Facility	As of September 30, 2019
Company/Facility	Total Facility		Usage		Available Liquidity
	Millions
PSEG	$	1,500	$	349	$	1,151
PSE&G	600		26		574
PSEG Power	2,100		176		1,924
Total	$	4,200	$	551	$	3,649

As of September 30, ~~2017,~~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

table of PSEG and PSE&G. In June 2017, S&P published updated research on Power and the rating and outlook remained unchanged. In July 2017, Moody’s upgraded PSEG’s senior unsecured rating to Baa1 from Baa2 and revised its outlook to Stable from Positive. Also in July, Moody’s affirmed the ratings at PSE&G and Power.contents

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 ~~$899~~$872 million and ~~$783~~$857 million as of September 30, ~~2017~~2019 and December 31, ~~2016,~~2018, respectively.

For additional information, see Item 1. Note ~~10.~~12. Debt and Credit Facilities.

Long-Term Debt Financing

During the next twelve months,, PSEG ~~has a floating rate $500 million term loan maturing in November 2017. PSE&G~~ has $400 million of ~~5.30% Medium-Term~~1.60% Senior Notes maturing in ~~May 2018 and $350~~November 2019. PSE&G has $250 million of ~~2.30% Medium-Term~~3.50% Medium Term Notes maturing in ~~September 2018.~~August 2020 and PSEG Power has $406 million of 5.13% Senior Notes maturing in April 2020.

For ~~a discussion of our long-term debt issuances and maturities during 2017,~~additional information see Item 1. Note ~~10.~~12. Debt and Credit Facilities.

Common Stock Dividends

On July ~~18, 2017,~~16, 2019, our Board of Directors ~~approved~~declared a ~~$0.43~~$0.47 dividend per share of common stock for the third quarter of ~~2017.~~2019. This reflects an indicative annual dividend rate of ~~$1.72~~$1.88 per share. We expect to continue to pay cash dividends on our common stock; however, the declaration and payment of future dividends to holders of our common stock will be at the discretion of the Board of Directors and will depend upon many factors, including our financial condition, earnings, capital requirements of our businesses, alternate investment opportunities, legal requirements, regulatory constraints, industry practice and other factors that the Board of Directors deems relevant. For additional information related to cash dividends on our common stock, see Item 1. ~~Note16.~~Note 18. Earnings Per Share (EPS) and Dividends.

Credit Ratings

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

~~In April 2017, S&P published updated research and affirmed the ratings and outlooks~~




	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.

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. There were no material changes to our projected capital expenditures as compared to amounts disclosed in our ~~2016~~ Form 10-K. See Executive Overview of 2019 and Future Outlook for additional information.

PSE&G

During the nine months ended September 30, ~~2017,~~2019, PSE&G made capital expenditures of ~~$2,118~~$1,866 million, primarily for T&D system reliability. This does not include expenditures for cost of removal, net of salvage, of ~~$72~~$87 million, which are included in operating cash flows.

In July 2017, PSE&G filed a petition with the BPU for a GSMP II program, requesting extension of our gas system modernization program through which PSE&G has proposed investing up to $540 million per year beginning in 2019 to continue to modernize our gas system. Under this proposed program, PSE&G plans to replace up to 1,250 miles of gas mains and associated service lines. This is not included in PSE&G’s projected capital expenditures.

PSEG Power

During the nine months ended September 30, ~~2017,~~2019, PSEG Power made capital expenditures of ~~$779~~$406 million, excluding $~~124~~101 million for nuclear fuel, primarily related to our ~~Keys, Sewaren 7,~~ BH5 and other generation projects.

ACCOUNTING MATTERS

For information related to recent accounting matters, see Item 1. Note 2. Recent Accounting Standards.


ITEM 3.	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 Condensed Consolidated Financial Statements.~~Notes. It is our policy to use derivatives to manage risk consistent with business plans and prudent practices. We have a Risk Management Committee comprised of executive officers who utilize a risk oversight function to ensure compliance with our corporate policies and risk management practices.

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

Commodity Contracts

The availability and price of energy-related commodities are subject to fluctuations from factors such as weather, environmental policies, changes in supply and demand, state and federal regulatory policies, market rules and other events. To reduce price

risk caused by market fluctuations, we enter into supply contracts and derivative contracts, including forwards, futures, swaps and options with approved counterparties. These contracts, in conjunction with physical sales and other services, help reduce risk and optimize the value of owned electric generation capacity.

Value-at-Risk (VaR) Models

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

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

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

From July through September ~~2017,~~2019, MTM VaR ~~remained~~was relatively stable between a low of $5$10 million and a high of $9$26 million at the 95% confidence level. The range of VaR was narrower for the three months ended September 30, ~~2017~~2019 as compared with the year ended December 31, ~~2016.~~

2018.

MTM VaR
Three Months Ended September 30, 2017 Year Ended December 31, 2016
Millions
95% Confidence Level, Loss could exceed VaR one day in 20 days
Period End $ 8
$ 26

Average for the Period $ 7
$ 16

High $ 9
$ 32

Low $ 5
$ 10

99.5% Confidence Level, Loss could exceed VaR one day in 200 days
Period End $ 13
$ 40

Average for the Period $ 11
$ 25

High $ 15
$ 51

Low $ 8
$ 16




	MTM VaR
	Three Months Ended September 30, 2019		Year Ended December 31, 2018
	Millions
95% Confidence Level, Loss could exceed VaR one day in 20 days
Period End	$	10	$	21
Average for the Period	$	16	$	14
High	$	26	$	46
Low	$	10	$	6
99.5% Confidence Level, Loss could exceed VaR one day in 200 days
Period End	$	16	$	32
Average for the Period	$	25	$	22
High	$	41	$	72
Low	$	15	$	9

See Item 1. Note ~~11.~~13. Financial Risk Management Activities for a discussion of credit risk.


ITEM 4.	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

There have been no changes in internal control over financial reporting that occurred during the third quarter of ~~2017~~2019 that have materially affected, or are reasonably likely to materially affect, each registrant’s internal control over financial reporting.

PART II. OTHER INFORMATION


ITEM 1.	LEGAL PROCEEDINGS

We are party to various lawsuits and environmental and regulatory matters, including in the ordinary course of business. For ~~additional~~ information regarding material legal proceedings, including updates to information reported in Item 3 of Part I of the ~~2016 Annual Report on~~ Form 10-K, see Part I, Item 1. Note 9.11. Commitments and Contingent Liabilities and Item 5. Other ~~Information.~~Information in the first and second quarter 2019 10-Qs and in this Quarterly Form 10-Q.


ITEM 1A.	RISK FACTORS

The discussion of our business and operations in this Quarterly Report on Form 10-Q should be read together with the risk factors contained in Part I, Item 1A of our ~~2016 Annual Report on~~ Form 10-K, ~~and our Quarterly Report on Form 10-Q for the quarter ended March 31, 2017,~~ which ~~describe~~describes various risks and uncertainties that 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. ~~Except as discussed below, there~~There have been no material changes to the risk factors set forth in the above-referenced ~~filings~~filing as of September 30, ~~2017.~~2019.

~~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, transmission and distribution 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 Independent System Operators (ISOs), among others. Our and third-party information technology systems may be vulnerable to cybersecurity attacks involving 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 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 have experienced and expect to continue to experience actual or attempted cyber-attacks on our information technology systems; however, none of these incidents has had a material impact on our operations or financial condition. If a significant cybersecurity event or breach should occur within our company or with one of our material vendors, we could be exposed to significant loss of revenue, material repair costs to intellectual and physical property, significant fines and penalties for non-compliance with existing laws and regulations, significant litigation costs, increased costs to finance our businesses, reputational damage 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 Part 1, Item 1. Regulatory Issues in our Annual Report on Form 10-K for the year ended December 31, 2016 and Item 5. Other Information in this Quarterly Report on Form 10-Q.

The market for cybersecurity insurance is relatively new and coverage available for cybersecurity events may 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.


ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

~~The following table indicates our~~In December 2018, we entered into a share repurchase plan that complies with Rule 10b5-1 of the Exchange Act, as amended, solely with respect to the repurchase of shares to satisfy obligations under equity compensation awards that are expected to vest or be exercised in 2019. There were no common share repurchases in the open market ~~to satisfy obligations under various equity compensation awards~~ during the third quarter of ~~2017~~.2019.

Three Months Ended September 30, 2017
Total Number
of Shares
Purchased

Average
Price Paid
per Share

July 1 - July 31 —
$ —

August 1 - August 31 135,277
$ 45.25

September 1- September 30 —
$ —

ITEM 5. OTHER INFORMATION

Certain information reported in the ~~2016 Annual Report on~~ Form 10-K is updated below. Additionally, certain information is provided for new matters that have arisen subsequent to the filing of the ~~2016 Annual Report on~~ Form 10-K and ~~the Quarterly Report on Form 10-Q for the quarters ended March 31, 2017~~first and ~~June 30, 2017.~~second quarter 2019 10-Qs. References are to the related pages on the ~~Forms~~Form 10-K and ~~10-Q as printed~~the first and ~~distributed.~~

~~Employee Relations~~

~~December 31, 2016 Form 10-K page 15.~~ ~~In 2016, six of our eight labor unions ratified extensions of their collective bargaining agreements with us, with expiration dates from~~second quarter 2019 ~~to 2021. In 2017, each of the remaining two unions ratified extensions of their collective bargaining agreements with us with expiration dates in 2021 and 2022.~~10-Qs.

Federal Regulation

~~FERC~~

Energy Clearing ~~Prices/Price Formation Initiatives~~Prices

December 31, ~~2016~~2018 Form 10-K page 16 and March 31, ~~2017~~2019 Form 10-Q on page ~~76.~~ 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.83. In April 2019, 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 byissued an order directing 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 recently 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 about energy market prices. We cannot predict what action FERC might ultimately take, but such an examination could lead to future rule changes.

In June 2017, PJM issued an energy price formation proposal to address a flaw in the energy market in which energy prices during off-peak periods often do not reflect the production costs of generators during these periods even though they are serving load. PJM’s proposal would allow large, inflexible units to set price. If placed into effect, this proposal will improve price formation by ensuring that the marginal costs of units serving load will be better reflected in clearing prices. We cannot predict the outcome of this matter.

~~Notice of Proposed Rulemaking on Baseload Generation~~

In September 2017, the Secretary of the U.S. Department of Energy issued a Notice of Proposed Rulemaking (NOPR) to allow a full recovery of costs for certain eligible units physically located within the FERC-approved organized markets. The NOPR directs FERC to take final action within 60 days. The NOPR contemplates a cost-of-service payment and a fair rate of return for units that are able to provide certain essential energy and ancillary reliability services, have a 90-day fuel supply on site and are not subject to cost-of-service rate regulation by any State or local authority. We are participating in this proceeding, but we are unable to predict the outcome.

~~Capacity Market Issues~~

~~December 31, 2016 Form 10-K page 16, March 31, 2017 Form 10-Q on page 76 and June 30, 2017 Form 10-Q on page 83.~~ ~~PJM, the~~ New York Independent System Operator, Inc. (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 ~~Independent System Operator New England, Inc. each have capacity markets~~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 ~~have been approved by~~new tariff provisions would apply fast-start pricing to all eligible fast-start resources; however, the new rules would not be implemented until FERC issues an order approving them. We will continue to participate in this process before FERC. ~~FERC regulates these markets and continues to examine whether~~

Environmental Matters

Climate Change—CO₂ Regulation under 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 or resource attributes, whether generators are being sufficiently compensated in the capacity market and whether subsidized resources may be adversely affecting capacity market prices. FERC held a technical conference to seek input from the industry on potential options to integrate public policy goals in wholesale markets. We cannot predict what action, if any, FERC might take with regard to capacity market designs.Clean Air Act

~~Capacity Market Issues—PJM~~

December 31, ~~2016~~2018 Form 10-K page ~~16, March 31, 2017 Form 10-Q on page 76~~21 and June 30, ~~2017~~2019 Form 10-Q page ~~83.~~ ~~PJM~~89. In June 2019, the EPA issued its final Affordable Clean Energy (ACE) rule as a ~~series~~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 ~~white papers in response~~emissions reductions” (BSER) as heat improvements to ~~public policies that seek~~be applied only to ~~recognize value associated~~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 generation plants beyond their cost effectiveness and reliability attributes. The three proposals are intended to spur stakeholder discussion and include both potential capacity and energy market reforms. The first energy market reform (see Energy Clearing Prices/Price Formation Initiatives) would allow inflexible generating units to set prices resulting in reduced uplift payments and improved

~~price signals while~~ the second energy market reform contemplates a voluntary carbon pricing program where states that elect to participate in the program would agree to put a price on carbon emissions. The capacity market proposal contemplates a two-stage capacity auction which, in its current form, would improve prices for unsubsidized resources, but would still continue to provide capacity payments for subsidized resources.

~~Transmission Regulation~~

~~December 31, 2016 Form 10-K page 18.~~ In October 2017, PSE&G filed its 2018 Annual Formula Rate Update with FERC which requests approximately $212 million in increased annual transmission revenues effective January 1, 2018, subject to true-up. Each year, transmission revenues are adjusted to reflect items such as updating estimates used in the filing with actual data. For additional information about our transmission formula rate, see Part I Item 1. Note 5. Rate Filings.

~~Transmission Regulation~~—~~Transmission Policy Developments~~

~~December 31, 2016 Form 10-K page 18, March 31, 2017 Form 10-Q on page 77 and June 30, 2017 Form 10-Q on page 83.~~

In a February 2016 order, FERC reversed a previous order and accepted a filing by the PJM transmission owners seeking authority to assign costs for Regional Transmission Expansion Plan projects (subject to PJM Board approval requirements) solely addressing localized needs to customers within the local transmission owner’s zone. FERC’s action in this order provides an exemption from the Order 1000 open window procedures for projects constructed by transmission owners to meet local transmission planning criteria. FERC’s orders have been challenged at the U.S.United States Court of Appeals for the ~~D.C. Circuit (D.C. Circuit) and PSE&G has intervened in support~~District of ~~FERC.~~

In April 2017, the PJM Board announced that it would be lifting the previously disclosed suspension of the Artificial Island transmission project and approved the award to PSE&G of the construction of necessary upgrade work at a cost of approximately $130 million. In October 2017, FERC accepted PJM’s filing on the grounds that PJM correctly applied its Tariff. However, FERC deferred a ruling on whether the cost allocation methodology applied to the Artificial Island project is appropriate. FERC will decide this issue in a separate proceeding that is currently pending. We are unable to predict the outcome.

~~Nuclear Regulatory Commission (NRC)~~

~~December 31, 2016 Form 10-K page 20.~~ The NRC continues to evaluate potential revisions to its requirements in connection with its operational and safety reviews of nuclear facilities in the United States as a result of the Fukushima Daiichi incident. We are also subject to cybersecurity regulations promulgated by the NRC.

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 our Salem, Hope Creek and Peach Bottom facilities, but such cost could be material.

~~State Regulation~~

~~Cybersecurity Requirements for Regulated Entities~~

~~December 31, 2016 Form 10-K page 21.~~ In March 2016, the BPU issued an order for the regulated electric, natural gas and water/wastewater utilities to further reduce the potential for cyber threats to the reliability and resiliency of utility service and to protect customers’ information. The order requires these regulated utilities, including PSE&G, to, among other conditions, implement a cybersecurity program that defines and implements organization accountabilities and responsibilities for cyber risk management activities, and establishes policies, plans, processes and procedures for identifying and mitigating cyber risk to critical systems. New Jersey utilities, including PSE&G, were required to be compliant with these requirements by October 1, 2017. We have submitted the required certification of compliance to the BPU.

In an effort to reduce the likelihood and severity of cyber incidents, we have a comprehensive cybersecurity program designed to protect and preserve the confidentiality, integrity and availability of our company and our customers’ information and our systems. In addition, we are subject to maintaining key cybersecurity controls to meet mandatory cybersecurity regulatory requirements. Our cybersecurity program is built on technical, procedural, and people-focused measures to detect, protect against, respond to, and recover from cyber threats to our systems and information including company, employee and customer data. Features of our program include: identifying critical information and systems; conducting cyber risk assessments of our and third party systems; maintaining awareness of cyber threats and vulnerabilities through partnerships with public and private entities, as well as industry groups; maintaining and testing our cybersecurity incident response plans and systems; training personnel on cybersecurity issues; and raising cybersecurity awareness throughout our company with electronic notices and seminars. We cannot assure that our cybersecurity program will be effective in preventing or mitigating cybersecurity incidents. For a discussion of the risks associated with cybersecurity threats, see Item 1A. Risk Factors.

~~Energy Efficiency 2017 Program (EE 2017)~~

In August 2017, the BPU approved PSE&G’s petition for an Energy Efficiency 2017 Program (EE 2017) to extend three existing energy efficiency subprograms (multi-family, direct install and hospital efficiency) and establish two new residential energy efficiency offerings. The two new offerings include deployment of smart thermostats and a pilot program to provide residential customers with energy usage information enabling them to reduce consumption. The Order allows PSE&G to extend the subprogram offerings and establish the residential energy efficiency sub-programs under its existing energy efficiency clause recovery process. The EE 2017 allows for $69 million of additional investment and $16 million of additional administrative and information technology costs. The EE 2017 was added as the 11th component of the GPRC rate effective September 1, 2017.

~~Consolidated Tax Adjustments (CTA)~~

~~December 31, 2016 Form 10-K page 21.~~ ~~New Jersey is one of only a few states that make CTA in setting rates for regulated utilities. These adjustments to rate base are madeduring the rate setting process and~~are intended to allocate to utility customers a portion of the tax benefits realized from the filing of a consolidated federal tax return by the utility’s parent corporation. The BPU has been considering the appropriateness of the adjustment and the methodology and mechanics of the calculation for some time. In October 2014, the BPU approved a proposal by its Staff that limits the tax benefit period to be considered in the calculation to five years, sets the distribution rate base adjustment at 25% of any such tax benefit and eliminates from the process any tax benefits tied to transmission earnings. In accordance with this October action, this CTA policy will be applied only with respect to future distribution rate base cases. In November 2014, the New Jersey Division of Rate Counsel appealed the BPU’s decision and in September 2017, the New Jersey Superior Court, Appellate Division granted that appeal on procedural grounds. While the issue has now been remanded to the BPU, it is not expected that application of a CTA will have a material impact on PSE&G’s current earnings or in its upcoming rate case filing.

~~Environmental Matters~~

~~Air Pollution Control~~

~~Hazardous Air Pollutants Regulation~~

~~December 31, 2016 Form 10-K page 22.~~ In June 2015, the U.S. Supreme Court held that it was unreasonable for the EPA to refuse to consider the materiality of costs in determining whether to regulate hazardous air pollutants from power plants. In April 2016, the EPA released the final Supplemental Finding that considers the materiality of costs in determining whether to regulate hazardous air pollutants from power plants in response to the U.S. Supreme Court’s ruling. Industry participants and various state authorities have filed petitions with the D.C.Columbia Circuit challenging the EPA’s ~~Supplemental Finding. The D.C. Circuit is holding the case in abeyance pending further directions from the EPA.~~narrow interpretation of BSER. We ~~do not expect this Supplemental Finding to impact operation of our facilities.~~

~~Climate Change~~

CO₂~~Regulation under the Clean Air Act (CAA)~~

~~December 31, 2016 Form 10-K page 23.In March 2017, the President of the United States issued an Executive Order that instructed the EPA to review the New Source Performance Standards that establish emissions standards for CO~~₂ for certain new fossil power plants and the Clean Power Plan (CPP), a greenhouse gas emissions regulation under the CAA for existing power plants that establishes state-specific emission rate targets based on implementation of the best system of emission reduction. In April 2017, the D.C. Circuit granted the EPA’s motion to hold the case in abeyance for at least 60 days while the agency reviews the rule, which was subsequently extended by the D.C. Circuit in August 2017. In October 2017, upon completion of the review, the EPA Administrator signed a proposed repeal of the CPP. The EPA Administrator concluded that the CPP exceeds the EPA’s statutory authority by considering measures that are beyond the control of the owners of the affected sources (fossil fuel-fired electric generating units). Whether the EPA chooses to propose a replacement rule has not been decided. PSEG cannot estimate the impact of ~~these actions~~this action on our business ~~and future~~or results of ~~operations at this time.~~operations.

~~Regional Greenhouse Gas Initiative (RGGI)~~

~~December 31, 2016 Form 10-K page 23.~~ ~~In response to concerns over global climate change, some states have developed initiatives to stimulate national climate legislation through CO~~₂emission reductions in the electric power industry. New Jersey withdrew from RGGI in 2012. However, certain northeastern states (RGGI States), including New York and Connecticut where we have generation facilities, have~~state-specific rules in place to enable the RGGI regulatory mandate in each state to cap and reduce CO~~₂ ~~emissions. These rules make allowances available through a regional auction whereby generators may acquire allowances that are each equal to one ton of CO~~₂ ~~emissions. Generators are required to submit an allowance for each ton emitted over a three-year period. Allowances are available through the auction or through secondary markets.~~

~~Table~~table of ~~Contents~~contents

~~In September 2017, the RGGI States announced their new post-2020 program for a cap on regional CO~~₂ ~~emissions, which would require a decline in CO~~₂ ~~emissions in 2021 and each year thereafter, resulting in a 30% reduction in the CO~~₂ ~~emissions cap by 2030.~~

~~Water Pollution Control~~

~~Steam Electric Effluent Guidelines~~

~~December 31, 2016 Form 10-K page 23, March 31, 2017 Form 10-Q on page 77 and June 30, 2017 Form 10-Q on page 85.~~ In September 2015, the EPA issued a new Effluent Limitation Guidelines Rule (ELG Rule) for steam electric generating units. The rule establishes new best available technology economically achievable (BAT) standards for fly ash transport water, bottom ash transport water, flue gas desulfurization and flue gas mercury control wastewater, and gasification wastewater. The EPA provides an implementation period for currently existing discharges of three years or up to eight years if a facility needs more time to implement equipment upgrades and provide supporting information to its permitting authority. In the intervening time period, existing discharge standards continue to apply. Power’s Bridgeport Harbor station and the jointly-owned Keystone and Conemaugh stations, have bottom ash transport water discharges and that are regulated under this rule. Keystone and Conemaugh also have flue gas desulfurization wastewaters regulated by the rule.

In April 2017, the EPA announced that it had granted a petition for reconsideration of the ELG Rule and issued an administrative stay of the compliance dates in the rule that were the subject of pending litigation. In June 2017, the EPA proposed a rule to postpone the compliance deadlines for the BAT limitations for the aforementioned waste streams. In September 2017, the EPA issued a rule postponing for two years compliance dates related solely to bottom ash transport water and flue gas desulfurization wastewater. The EPA has announced plans to issue a new rule by November 2020 addressing revised requirements and compliance dates for these two waste streams. Power is unable to determine how this will ultimately impact its compliance requirements or its financial condition and results of operations.

~~Cooling Water Intake Structure~~

~~December 31, 2016 Form 10-K page 24.~~ In May 2014, the EPA issued a final cooling water intake rule under Section 316(b) of the Clean Water Act (CWA) that establishes new 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. In September 2014, several environmental non-governmental groups and certain energy industry groups filed petitions for review of the rule and the case has been assigned to the U.S. Second Circuit Court of Appeals (Second Circuit). Environmental organizations, including but not limited to the environmental petitioners in the Second Circuit, have also filed suit under the Endangered Species Act. The cases were subsequently consolidated at the Second Circuit and a decision remains pending.


ITEM 6.	EXHIBITS

A listing of exhibits being filed with this document is as follows:



a. PSEG:
Exhibit 1010.1:		Supplemental Executive Retirement Income Plan, amended effective July 1, 2019
Exhibit 10.2:		Retirement Income Reinstatement Plan for Non-Represented Employees, amended effective July 1, 2019
Exhibit 10.3:		Key Executive Severance Plan of Public Service Enterprise Group Incorporated, ~~Amended~~amended effective July ~~18, 2017~~1, 2019
Exhibit ~~12:~~31:		~~Computation of Ratios of Earnings to Fixed Charges~~
~~Exhibit 31:~~		Certification by Ralph Izzo Pursuant to Rules 13a-14 and 15d-14 of the 1934 Act
Exhibit 31.1:		Certification by Daniel J. Cregg Pursuant to Rules 13a-14 and 15d-14 of the 1934 Act
Exhibit 32:		Certification by Ralph Izzo Pursuant to Section 1350 of Chapter 63 of Title 18 of the U.S. Code
Exhibit 32.1:		Certification by Daniel J. Cregg Pursuant to Section 1350 of Chapter 63 of Title 18 of the U.S. Code
Exhibit 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.
Exhibit 101.SCH:		Inline XBRL Taxonomy Extension Schema
Exhibit 101.CAL:		Inline XBRL Taxonomy Extension Calculation Linkbase
Exhibit 101.LAB:		Inline XBRL Taxonomy Extension Labels Linkbase
Exhibit 101.PRE:		Inline XBRL Taxonomy Extension Presentation Linkbase
Exhibit 101.DEF:		Inline XBRL Taxonomy Extension Definition Document
Exhibit 104:		Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)

b. PSE&G:
Exhibit 1010.1:		Supplemental Executive Retirement Income Plan, amended effective July 1, 2019
Exhibit 10.2:		Retirement Income Reinstatement Plan for Non-Represented Employees, amended effective July 1, 2019
Exhibit 10.3:		Key Executive Severance Plan of Public Service Enterprise Group Incorporated, ~~Amended~~amended effective July ~~18, 2017~~1, 2019
Exhibit ~~12.1:~~31.2:		~~Computation of Ratios of Earnings to Fixed Charges Plus Preferred Securities Dividend Requirements~~
~~Exhibit 31.2:~~		Certification by Ralph Izzo Pursuant to Rules 13a-14 and 15d-14 of the 1934 Act
Exhibit 31.3:		Certification by Daniel J. Cregg Pursuant to Rules 13a-14 and 15d-14 of the 1934 Act
Exhibit 32.2:		Certification by Ralph Izzo Pursuant to Section 1350 of Chapter 63 of Title 18 of the U.S. Code
Exhibit 32.3:		Certification by Daniel J. Cregg Pursuant to Section 1350 of Chapter 63 of Title 18 of the U.S. Code
Exhibit 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.
Exhibit 101.SCH:		Inline XBRL Taxonomy Extension Schema
Exhibit 101.CAL:		Inline XBRL Taxonomy Extension Calculation Linkbase
Exhibit 101.LAB:		Inline XBRL Taxonomy Extension Labels Linkbase
Exhibit 101.PRE:		Inline XBRL Taxonomy Extension Presentation Linkbase
Exhibit 101.DEF:		Inline XBRL Taxonomy Extension Definition Document
Exhibit 104:		Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)

c. PSEG Power:
Exhibit 1010.1:		Supplemental Executive Retirement Income Plan, amended effective July 1, 2019
Exhibit 10.2:		Retirement Income Reinstatement Plan for Non-Represented Employees, amended effective July 1, 2019
Exhibit 10.3:		Key Executive Severance Plan of Public Service Enterprise Group Incorporated, ~~Amended~~amended effective July ~~18, 2017~~1, 2019
Exhibit ~~12.2:~~31.4:		~~Computation of Ratios of Earnings to Fixed Charges~~
~~Exhibit 31.4:~~		Certification by Ralph Izzo Pursuant to Rules 13a-14 and 15d-14 of the 1934 Act
Exhibit 31.5:		Certification by Daniel J. Cregg Pursuant to Rules 13a-14 and 15d-14 of the 1934 Act
Exhibit 32.4:		Certification by Ralph Izzo Pursuant to Section 1350 of Chapter 63 of Title 18 of the U.S. Code
Exhibit 32.5:		Certification by Daniel J. Cregg Pursuant to Section 1350 of Chapter 63 of Title 18 of the U.S. Code



Exhibit 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.
Exhibit 101.SCH:		Inline XBRL Taxonomy Extension Schema
Exhibit 101.CAL:		Inline XBRL Taxonomy Extension Calculation Linkbase
Exhibit 101.LAB:		Inline XBRL Taxonomy Extension Labels Linkbase
Exhibit 101.PRE:		Inline XBRL Taxonomy Extension Presentation Linkbase
Exhibit 101.DEF:		Inline XBRL Taxonomy Extension Definition Document
Exhibit 104:		Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)

~~Table~~

table of ~~Contents~~contents

SIGNATURE

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
(Registrant)

By:	/S/ S~~TUART~~ ~~J. BLACK~~ROSE M. CHERNICK
	~~Stuart J. Black~~Rose M. Chernick Vice President and Controller (Principal Accounting Officer)

Date: October 31, ~~2017~~2019

SIGNATURE



PUBLIC SERVICE ELECTRIC AND GAS COMPANY
(Registrant)

By:	/S/ S~~TUART~~ ~~J. BLACK~~ROSE M. CHERNICK
	~~Stuart J. Black~~Rose M. Chernick Vice President and Controller (Principal Accounting Officer)

Date: October 31, ~~2017~~2019