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 an Operations Services Agreement (OSA); PSEG Energy Holdings L.L.C. (Energy Holdings), which primarily has investments in leveraged leases; and PSEG Services Corporation (Services), which provides certain management, administrative and general services to PSEG and its subsidiaries at cost.

Power maintains an external master trust fund to provide for the costs of decommissioning upon termination of operations of its nuclear facilities. In addition, PSEG maintains a ~~Business~~grantor trust which was established to meet the obligations related to its non-qualified pension plans and deferred compensation plans, commonly referred to as a “Rabbi Trust.”

This accounting standard was ~~issued mainly~~adopted on January 1, 2018. Under the new guidance, equity investments in Power’s Nuclear Decommissioning Trust (NDT) and PSEG’s Rabbi Trust Funds are measured at fair value with the unrealized gains and losses now recognized through Net Income instead of Other Comprehensive Income (Loss). The debt securities in these trusts continue to ~~provide more consistency~~be classified as available-for-sale with the unrealized gains and losses recorded as a component of Accumulated Other Comprehensive Income (Loss). Realized gains and losses on both equity and available-for-sale debt security investments are recorded in earnings and are included with the unrealized gains and losses on equity securities in Net Gains (Losses) on Trust Investments. Other-than-temporary impairments on NDT and Rabbi Trust securities are also included in Net Gains (Losses) on Trust Investments. A cumulative effect adjustment was made to reclassify the net unrealized gains related to equity investments of $342 million ($176 million, net of tax) from Accumulated Other Comprehensive Income to Retained Earnings on January 1, 2018. See Note 16. Accumulated Other Comprehensive Income (Loss), Net of Tax and Note 8. Trust Investments for further discussion.

This accounting standard reduces the diversity in practice in how certain cash receipts and cash payments are presented and classified in the ~~definition~~Statement 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.Cash Flows.

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~~on January 1, 2018 using a ~~solar project. This standard upon adoption~~retrospective transition method and had no ~~impact~~changes in its presentation of its Statement of Cash Flows for each period presented.

This accounting standard was adopted on ~~PSEG’s financial statements.~~January 1, 2018. PSEG will continue the current balance sheet classification of restricted cash or restricted cash equivalents. PSEG has provided a reconciliation of cash and cash equivalents and restricted

cash or restricted cash equivalents and has included a description of these amounts in Note 1. Organization, Basis of Presentation and Significant Accounting Policies. The effect of adoption on the September 30, 2018 Consolidated Statements of Cash Flows was immaterial.

This accounting standard was adopted on January 1, 2018. Under the new guidance, entities are required 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 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 is eligible for capitalization, when applicable. As a result of adopting this standard, PSE&G reduced its charge to expense for the three and nine months ended September 30, 2018 by approximately $15 million and $44 million, respectively. The Condensed Consolidated Statements of Operations were recast to show retrospective adjustments of the non-service cost components of net benefit credits (costs) of $(2) million and $(5) million at PSE&G and $2 million and $6 million at Power, for the three and nine months ended September 30, 2017, respectively, from O&M Expense to a new line item after Operating Income entitled Non-Operating Pension and OPEB Credits (Costs). See Note 9. Pension and Other Postretirement Benefits (OPEB).

This accounting standard was adopted on January 1, 2018. The standard will be applied prospectively to awards modified on or after January 1, 2018. PSEG does not expect a material impact from adoption of this new standard.

~~Revenue from Contracts with Customers~~Leases—ASU 2016-02, updated by ASUs 2018-01, 2018-10 and 2018-11

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 standard is effective for annual and interim periods beginning after December 15, 2018 with retrospective application to previously issued financial statements for 2018 and 2017. Early application is permitted. PSEG is currently analyzing the impact of this standard on its financial statements.2018.

This accounting standard’s amendments more closely align hedge accounting with the companies’ risk management activities in the financial statements. The amendments expand hedge accounting for both non-financial and financial risk components by

The new guidance is effective for annual and interim periods beginning after December 15, 2018. The standard requires using a modified retrospective method upon adoption. Early adoption is permitted. 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 is not expected to have a material impact on PSEG’s financial statements.

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.

This accounting standard would affect any entity that is required to apply the provisions of the Accounting Standards Codification (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 would allow entities to record a reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the newly enacted federal corporate income tax rate. The amount of the reclassification would be the difference between the historical corporate income tax rate and the newly enacted 21% corporate income tax rate.

The standard is effective for all entities for annual periods and interim periods within those annual periods beginning after December 15, 2018. Early adoption is permitted for an entity in any interim or annual period for public business entities for reporting periods for which financial statements have not yet been issued or made available for issuance.

An entity would be able to choose to apply this standard retrospectively to each period (or periods) in which the effect of the change in the U.S. federal corporate income tax rate in the new tax legislation enacted in 2017 is recognized or apply the standard in the reporting period adopted. PSEG is currently analyzing the impact this standard, if adopted, could have on its consolidated financial statements.

Measurement of Credit Losses on Financial Instruments—ASU 2016-13

This accounting standard provides a new model for recognizing credit losses on financial assets carried at amortized cost. 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 securities should 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 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 the annual or interim periods after December 15, 2018. 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~~Disclosure Framework—Changes to the Disclosure Requirements for Fair Value Measurement—ASU 2018-13

This accounting standard ~~reduces~~modifies the ~~diversity in practice in how~~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 ~~cash receipts and cash payments are presented and classified in the Statement of Cash Flows.~~other disclosure requirements for Level 3 fair value measurements.

The standard is effective for annual and interim periods beginning after December 15, ~~2017; however, entities may adopt early, including~~2019. Certain amendments in anthe standard should be applied prospectively for only the most recent interim ~~period. PSEG does not anticipate any current impact on PSEG’s financial statements. PSEG will adopt this~~or annual period presented in the initial fiscal year of adoption. All other amendments of the standard asshould be applied retrospectively to all periods presented upon their effective date. Early adoption is permitted.

Customer’s Accounting for Implementation Costs Incurred in a ~~retrospective transition method to each period presented.~~

This accounting standard aligns the capitalization requirements for implementation costs incurred in a hosting arrangement that is a service contract with capitalization requirements for implementation costs incurred to develop or obtain internal-use software, including hosting arrangements that include an internal use software license. The standard follows the guidance in ASC 350—Intangibles—Goodwill and Other to determine which implementation costs to capitalize as an asset related to the service contract and which costs to expense. The standard requires ~~entities~~the amortization of capitalized costs to ~~explain~~be presented in O&M Expense. In addition, the ~~change during the period~~standard also adds presentation requirements for these costs in the ~~total~~statements of cash ~~cash equivalents~~flows 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.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 should be applied either retrospectively or prospectively to all implementation costs incurred after the date of adoption. 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 standard on a prospective basis and 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~~interest crediting rates have been added and certain clarifications were made to other disclosure requirements.

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

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 ~~new guidance, entities~~product(s) and/or services are ~~required~~delivered to ~~report~~the customer. The electric and gas commodity and delivery tariffs are recurring contracts in effect until cancellation by the customer. Revenue is recognized over time as the service ~~cost component~~is rendered to the customer. Included in PSE&G’s regulated revenues are unbilled electric and gas revenues which represent the ~~same line item or items as other compensation costs arising from~~estimated amount customers will be billed for services rendered from the most recent meter reading to the end of the respective accounting period.

PSE&G’s transmission revenues are earned under a separate FERC tariff. The performance obligation of transmission service is satisfied over time as it is provided to and consumed by ~~their employees during~~ the ~~period.~~customer. Revenue is recognized upon delivery of the transmission service. PSE&G’s revenues from the transmission of electricity are recorded based on a FERC-approved annual formula rate mechanism. This mechanism provides for an annual filing of an estimated revenue requirement with rates effective January 1 of each year and a mechanism true-up to that estimate based on actual revenue requirements. The ~~other components~~true-up mechanism is an alternative revenue which is outside the scope of ~~net benefit~~revenue from contracts with customers.

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

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

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.

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

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

Gas Contracts—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, which extends through March 2019, will renew year-to-year thereafter unless terminated by either party with a two year notice. The performance obligation is primarily delivery of gas which is satisfied over time. Revenue is recognized as gas is delivered. Based upon the availability of natural gas, storage and pipeline capacity beyond PSE&G’s daily needs, Power also sells gas and pipeline capacity to other counterparties under bilateral contracts. The performance obligation under these contracts is satisfied over time upon delivery of the gas or capacity, and revenue is recognized accordingly.

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.

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.

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




	PSE&G		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		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

PSE&G does 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, 2018 and December 31, 2017. Substantially all of PSE&G’s accounts receivable result from contracts with customers. Allowances represented approximately seven percent of accounts receivable as of September 30, 2018 and December 31, 2017.

Power generally collects consideration upon satisfaction of performance obligations, and therefore, Power had no material contract balances as of September 30, 2018 and December 31, 2017.

Power’s accounts receivable include amounts resulting from contracts with customers and other contracts which are out of scope of accounting guidance for revenues from contracts with customers. The majority of these accounts receivable are subject to master netting agreements. As a result, accounts receivable resulting from contracts with customers and receivables unrelated to contracts with customers are netted within Accounts Receivable and Accounts Payable on the Condensed Consolidated Balance Sheets. In the wholesale energy markets in which 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 Power typically records no allowances.

PSEG LI does not have any material contract balances as of September 30, 2018 and December 31, 2017.

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

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

Capacity Payments from the PJM Reliability Pricing Model (RPM) Annual Base Residual and Incremental Auctions—The Base Residual Auction is conducted annually three years in advance of the operating period. Power expects to realize the following average capacity prices for capacity obligations to be ~~presented~~satisfied resulting from the base and incremental auctions which have been completed:

Capacity Payments from the New England ISO Forward Capacity Market—The Forward Capacity Market Auction (FCM) is conducted annually three years in advance of the operating period. The table below includes Power’s cleared capacity in the ~~Statement~~FCM for the Bridgeport Harbor Station 5, which cleared the 2019/2020 auction at $231/MW-day for seven years, with escalations based on the Handy-Whitman Index and the planned retirement of ~~Operations separately~~Bridgeport Harbor Station 3 in 2021. Power expects to realize the following average capacity prices for capacity obligations to be satisfied resulting from the ~~service cost component after Operating Income. Additionally, only the service cost component will be eligible for capitalization, when applicable.~~FCM auctions which have been completed:

Bilateral capacity contracts—Capacity obligations pursuant to contract terms through 2029 are anticipated to result in revenues totaling $171 million.

The ~~standard requires the amendments to be applied retrospectively~~LIPA OSA is a 12-year services contract ending in 2025 with annual fixed and incentive components. The fixed fee for the ~~presentation~~provision of ~~the service cost component~~services thereunder in 2018 is $64 million and ~~the other cost components of net periodic pension cost and net periodic OPEB cost in the Statement of Operations and prospectively,~~could increase each year based on ~~and after~~ the ~~effective date, for the capitalization of the service cost component of net periodic pension and OPEB costs.~~

As of June 1, 2017, Power recognized total ~~D&A~~Depreciation and Amortization of $964 million for the Hudson and Mercer units to reflect the ~~end~~significant shortening of their expected economic useful lives in 2017. In the three and nine months ended September 30, 2017, Power recognized pre-tax charges ~~in Energy Costs~~ of $1 million and $10 million, respectively, in Energy Costs primarily for coal inventory lower of cost or market adjustments. ~~For~~In the three 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 ana net increase in the Asset Retirement Obligation liability due to settlements and changes in cash flow estimates, partially offset by changes in employee-related severance costs. In 2018, no material costs were recorded. Power ~~currently anticipates~~is exploring various opportunities with

PSEG and Power continue to monitor their other coal assets, including the Keystone and Conemaugh generating stations, to assess their economic viability through the end of their designated useful lives and their continued classification as held for use. The precise timing of a change 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 held for use classification of our remaining coal units may have a material adverse impact on PSEG’s and Power’s future financial results.

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 and

Electric and Gas Distribution Base Rate Filings—In October 2018, the BPU issued an Order approving the settlement of PSE&G’s distribution base rate case with new rates effective November 1, 2018. The settlement resulted in a net reduction in overall annual revenues of approximately $13 million, comprised of a $212 million increase in base revenues, including recovery of deferred storm costs, offset by the return of tax benefits of approximately $225 million. The tax benefits include the flow-back 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. As a result of the agreement to flow back tax repair-related accumulated deferred income taxes in the settlement, PSE&G recognized a $581 million regulatory liability and a corresponding regulatory asset as of September 30, 2018. The Order provides for a $9.5 billion rate base, a 9.6% return on equity for PSE&G’s distribution business and a 54% equity component of its capitalization structure. In addition to the $13 million annual revenue reduction, the Order provides for a $28 million one-time refund to customers in November and December 2018 for taxes collected at the higher federal income tax rate for the January 1 to March 31, 2018 period. The BPU approved a rate reduction effective April 1, 2018, to PSE&G’s then current electric and gas base rates of approximately $71 million and $43 million, respectively, on an annual basis, to reflect the lower federal income tax rate for the period April 1 and forward.

Transmission Formula Rate Filings—In ~~June 2017,~~October 2018, PSE&G made two FERC filings with respect to its Transmission Formula Rate. PSE&G filed its ~~2016~~2019 Annual Transmission Formula Rate update with FERC requesting approximately $100 million in increased annual transmission revenue effective January 1, 2019, subject to true-up. In addition, PSE&G filed a Section 205 filing that seeks FERC approval to refund approximately $155 million of transmission related “unprotected excess deferred income tax benefits” to transmission customers over the 2019 twelve month period. The amount of unprotected excess deferred taxes is subject to change pending further Internal Revenue Service (IRS) guidance. FERC approval of PSE&G’s Section 205 filing is required to commence any refund to customers and as such, the Annual Transmission Formula Rate update request does not include the impact of the tax refund. This matter is pending.

In June 2018, PSE&G filed its 2017 true-up adjustment pertaining to its transmission formula rates in effect for ~~2016.~~2017. This resulted in an adjustment of ~~$12~~$27 million more than the ~~2016~~2017 originally filed ~~revenues.~~revenues, the impact of which PSE&G had primarily recognized in its Consolidated Statement of Operations for the year ended December 31, 2017.

Net unrealized gains (losses) on debt securities of $(17) million (after-tax) were included in Accumulated Other Comprehensive Loss on PSEG’s and Power’s Condensed Consolidated Balance Sheets as of September 30, 2018. The portion of net unrealized gains (losses) recognized during the third quarter and first nine months of 2018 related to equity securities still held at the end of September 30, 2018 were $41 million and $26 million, respectively.

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 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 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, 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
$ —




	As of September 30, 2018										As of December 31, 2017
	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)	$	70	$	(2	)	$	28	$	(2	)	$	28	$	—		$	25	$	(1	)
Corporate (B)	76		(3		)	14		—			39		(1		)	9		—
Total Available-for-Sale Debt Securities	146		(5		)	42		(2		)	67		(1		)	34		(1		)
Rabbi Trust Investments	$	146	$	(5	)	$	42	$	(2	)	$	67	$	(1	)	$	34	$	(1	)

The following tabular disclosure does not include the offsetting of trade receivables and payables.




	As of September 30, 2018
	Power (A)									Consolidated
	Not Designated
Balance Sheet Location	Energy- Related Contracts			Netting (B)			Total Power			Total Derivatives
	Millions
Derivative Contracts
Current Assets	$	301		$	(290	)	$	11		$	11
Noncurrent Assets	123			(121		)	2			2
Total Mark-to-Market Derivative Assets	$	424		$	(411	)	$	13		$	13
Derivative Contracts
Current Liabilities	$	(389	)	$	376		$	(13	)	$	(13	)
Noncurrent Liabilities	(149		)	147			(2		)	(2		)
Total Mark-to-Market Derivative (Liabilities)	$	(538	)	$	523		$	(15	)	$	(15	)
Total Net Mark-to-Market Derivative Assets (Liabilities)	$	(114	)	$	112		$	(2	)	$	(2	)

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

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




	As of December 31, 2017
	Power (A)									Consolidated
	Not Designated
Balance Sheet Location	Energy- Related Contracts			Netting (B)			Total Power			Total Derivatives
	Millions
Derivative Contracts
Current Assets	$	391		$	(362	)	$	29		$	29
Noncurrent Assets	78			(71		)	7			7
Total Mark-to-Market Derivative Assets	$	469		$	(433	)	$	36		$	36
Derivative Contracts
Current Liabilities	$	(403	)	$	387		$	(16	)	$	(16	)
Noncurrent Liabilities	(95		)	90			(5		)	(5		)
Total Mark-to-Market Derivative (Liabilities)	$	(498	)	$	477		$	(21	)	$	(21	)
Total Net Mark-to-Market Derivative Assets (Liabilities)	$	(29	)	$	44		$	15		$	15

(A)

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

(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, 2018 and December 31, 2017, Power had net cash collateral/margin payments to counterparties of $223 million and $146 million, respectively. Of these net cash/collateral ~~(received) paid~~margin payments $112 million as of ~~$(14)~~September 30, 2018 and $44 million ~~was~~as December 31, 2017 were netted against the corresponding net derivative contract positions. Of the $112 million as of September 30, 2018, $(2) million was netted against current assets, and $(1) million was netted against noncurrent assets, $88 million was netted against current liabilities, and $27 million was netted against noncurrent liabilities. Of the $44 million as of December 31, 2017, $(3) million was netted against current assets, $28 million was netted against current liabilities, and $19 million was netted against noncurrent liabilities.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Table 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 Power’s derivative instruments contain provisions that require Power to post collateral. This collateral may be posted in the form of cash or credit support with thresholds contingent upon Power’s credit rating from each of the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. These credit risk-related contingent features stipulate that if 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 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. 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~~$23 million and ~~$19~~$30 million as of September 30, ~~2017~~2018 and December 31, ~~2016,~~2017, respectively. As of ~~each of~~ September 30, ~~2017~~2018 and December 31, ~~2016,~~2017, Power had the contractual right of offset of $9$7 million and $13 million, respectively, related to derivative instruments that are assets with the same counterparty under master agreements and net of margin posted. If Power had been downgraded to a below investment grade rating, it would have had additional collateral obligations of $7$16 million and ~~$10~~$17 million as of September 30, ~~2017~~2018 and December 31, ~~2016,~~2017, respectively, related to its derivatives, net of the contractual right of offset under master agreements and the application of collateral.

The following ~~shows~~reconciles 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~~ ~~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
$ —

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
$ —

~~There were no pre-tax gains (losses) recognized in income on derivatives (ineffective portion) as of September 30, 2017 and~~

~~2016.~~

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(UNAUDITED)~~

~~Table of Contents~~

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

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, 2016	$	3		$	2
Gain Recognized in AOCI	—			—
Less: Gain Reclassified into Income	(3		)	(2		)
Balance as of December 31, 2017	$	—		$	—
Loss Recognized in AOCI	(2		)	(1		)
Less: Loss Reclassified into Income	—			—
Balance as of September 30, 2018	$	(2	)	$	(1	)

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~~2018 and ~~2016.~~2017. 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 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,
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 the gross volume, on an absolute value basis, of derivatives as of September 30, 2017 and December 31, 2016.~~

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
—
—



		��
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						Pre-Tax Gain (Loss) Recognized in Income on Derivatives
			Three Months Ended						Nine Months Ended
			September 30,						September 30,
			2018			2017			2018			2017
			Millions
PSEG and Power
Energy-Related Contracts	Operating Revenues		$	(130	)	$	26		$	(154	)	$	216
Energy-Related Contracts	Energy Costs		5			(4		)	12			(14		)
Total PSEG and Power			$	(125	)	$	22		$	(142	)	$	202

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Table of Contents

The following table summarizes the net notional volume purchases/(sales) of open derivative transactions by commodity as of September 30, 2018 and December 31, 2017.




Type	Notional	Total		PSEG	Power		PSE&G
		Millions
As of September 30, 2018
Natural Gas	Dekatherm (Dth)	281		—	281		—
Electricity	MWh	(66	)	—	(66	)	—
Financial Transmission Rights (FTRs)	MWh	24		—	24		—
As of December 31, 2017
Natural Gas	Dth	154		—	154		—
Electricity	MWh	(63	)	—	(63	)	—
FTRs	MWh	6		—	6		—

Credit Risk

Credit risk relates to the risk of loss that 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 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 Power’s credit risk from ~~others,~~wholesale counterparties, net of collateral, as of September 30, ~~2017.~~2018. 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 Power’s credit risk by credit rating of the counterparties.

As of September 30, 2018, 97% of the net credit exposure for 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	$	112	$	12	$	100	2	$	50	(A)
Non-Investment Grade	6		2		4		—	—
Total	$	118	$	14	$	104	2	$	50


(A)	~~Includes~~Represents net exposure of ~~$97~~$39 million with PSE~~&G.~~&G and $11 million with a non-affiliated counterparty.

As of September 30, ~~2017,~~2018, collateral held from counterparties where Power had credit exposure included $3$2 million in cash collateral and ~~$53~~$12 million in letters of credit.

As of September 30, ~~2017~~2018, Power had ~~144~~137 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,~~2018, primarily all of the posted collateral was in the form of parental guarantees. The unsecured credit used by the suppliers

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Table of Contents

represents PSE&G’s net credit exposure. PSE&G’s BGS suppliers’ credit exposure is calculated each business day. As of September 30, ~~2017,~~2018, PSE&G had no net credit exposure with suppliers, including 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)~~

~~Table of Contents~~

Note ~~12.~~13. 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 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,~~2018, these consisted 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 Power’s respective assets and (liabilities) measured at fair value on a recurring basis as of September 30, ~~2017~~2018 and December 31, ~~2016,~~2017, 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 Power.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Table of Contents

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, 2018
Description	Total			Netting (C)			Quoted Market Prices for Identical Assets (Level 1)			Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
	Millions
PSEG
Assets:
Energy-Related Contracts (A)	$	13		$	(411	)	$	12		$	404		$	8
NDT Fund (B)
Equity Securities	$	1,120		$	—		$	1,118		$	2		$	—
Debt Securities—U.S. Treasury	$	209		$	—		$	—		$	209		$	—
Debt Securities—Govt Other	$	311		$	—		$	—		$	311		$	—
Debt Securities—Corporate	$	456		$	—		$	—		$	456		$	—
Rabbi Trust (B)
Equity Securities	$	25		$	—		$	25		$	—		$	—
Debt Securities—U.S. Treasury	$	60		$	—		$	—		$	60		$	—
Debt Securities—Govt Other	$	39		$	—		$	—		$	39		$	—
Debt Securities—Corporate	$	101		$	—		$	—		$	101		$	—
Liabilities:
Derivative Contracts:
Energy-Related Contracts (A)	$	(15	)	$	523		$	(10	)	$	(519	)	$	(9	)
PSE&G
Assets:
Rabbi Trust (B)
Equity Securities	$	5		$	—		$	5		$	—		$	—
Debt Securities—U.S. Treasury	$	12		$	—		$	—		$	12		$	—
Debt Securities—Govt Other	$	8		$	—		$	—		$	8		$	—
Debt Securities—Corporate	$	21		$	—		$	—		$	21		$	—
Power
Assets:
Derivative Contracts:
Energy-Related Contracts (A)	$	13		$	(411	)	$	12		$	404		$	8
NDT Fund (B)
Equity Securities	$	1,120		$	—		$	1,118		$	2		$	—
Debt Securities—U.S. Treasury	$	209		$	—		$	—		$	209		$	—
Debt Securities—Govt Other	$	311		$	—		$	—		$	311		$	—
Debt Securities—Corporate	$	456		$	—		$	—		$	456		$	—
Rabbi Trust (B)
Equity Securities	$	6		$	—		$	6		$	—		$	—
Debt Securities—U.S. Treasury	$	15		$	—		$	—		$	15		$	—
Debt Securities—Govt Other	$	10		$	—		$	—		$	10		$	—
Debt Securities—Corporate	$	26		$	—		$	—		$	26		$	—
Liabilities:
Derivative Contracts:
Energy-Related Contracts (A)	$	(15	)	$	523		$	(10	)	$	(519	)	$	(9	)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Table of Contents

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)~~

~~Table of Contents~~




	Recurring Fair Value Measurements as of December 31, 2017
Description	Total			Netting (C)			Quoted Market Prices for Identical Assets (Level 1)			Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
	Millions
PSEG
Assets:
Cash Equivalents (D)	$	223		$	—		$	223		$	—		$	—
Derivative Contracts:
Energy-Related Contracts (A)	$	36		$	(433	)	$	15		$	442		$	12
NDT Fund (B)
Equity Securities	$	1,147		$	—		$	1,145		$	2		$	—
Debt Securities—U.S. Treasury	$	314		$	—		$	—		$	314		$	—
Debt Securities—Govt Other	$	270		$	—		$	—		$	270		$	—
Debt Securities—Corporate	$	402		$	—		$	—		$	402		$	—
Rabbi Trust (B)
Equity Securities	$	27		$	—		$	27		$	—		$	—
Debt Securities—U.S. Treasury	$	51		$	—		$	—		$	51		$	—
Debt Securities—Govt Other	$	34		$	—		$	—		$	34		$	—
Debt Securities—Corporate	$	119		$	—		$	—		$	119		$	—
Liabilities:
Derivative Contracts:
Energy-Related Contracts (A)	$	(21	)	$	477		$	(8	)	$	(485	)	$	(5	)
PSE&G
Assets:
Cash Equivalents (D)	$	223		$	—		$	223		$	—		$	—
Rabbi Trust (B)
Equity Securities	$	5		$	—		$	5		$	—		$	—
Debt Securities—U.S. Treasury	$	10		$	—		$	—		$	10		$	—
Debt Securities—Govt Other	$	7		$	—		$	—		$	7		$	—
Debt Securities—Corporate	$	24		$	—		$	—		$	24		$	—
Power
Assets:
Derivative Contracts:
Energy-Related Contracts (A)	$	36		$	(433	)	$	15		$	442		$	12
NDT Fund (B)
Equity Securities	$	1,147		$	—		$	1,145		$	2		$	—
Debt Securities—U.S. Treasury	$	314		$	—		$	—		$	314		$	—
Debt Securities—Govt Other	$	270		$	—		$	—		$	270		$	—
Debt Securities—Corporate	$	402		$	—		$	—		$	402		$	—
Rabbi Trust (B)
Equity Securities	$	6		$	—		$	6		$	—		$	—
Debt Securities—U.S. Treasury	$	13		$	—		$	—		$	13		$	—
Debt Securities—Govt Other	$	8		$	—		$	—		$	8		$	—
Debt Securities—Corporate	$	30		$	—		$	—		$	30		$	—
Liabilities:
Derivative Contracts:
Energy-Related Contracts (A)	$	(21	)	$	477		$	(8	)	$	(485	)	$	(5	)


(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 based on market prices, basis adjustments and other premiums where adjustments and premiums are not considered

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Table of Contents

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 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 of cash as of September 30, 2017 and $1 million as of December 31, 2016, which is part of the NDT Fund.~~ The NDT Fund maintains investments in various equity and fixed income ~~securities classified as “available for sale.”~~securities. The Rabbi Trust maintains investments in various fixed income securities and 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.fund. 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 Dreyfus 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 also has an equity index fund which is valued based on quoted prices in an active market.

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)

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 12. Financial Risk Management Activities for additional detail.


(D)	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)~~

~~Table of Contents~~

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 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 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 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 gas physical contracts have an unobservable component in their respective forward price curves, the fluctuations in fair value have been driven primarily by changes in the observable inputs. The following tables provide details surrounding significant Level 3 valuations as of September 30, ~~2017~~2018 and December 31, ~~2016.~~2017.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Table of Contents

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, 2018

Technique(s)

Input

Range

Assets

(Liabilities)

Millions

Power

Electricity

Electric Load Contracts

$

—

$

(9

)

Discounted Cash flow

Historic Load Variability

0% to 10%

Gas

Gas Physical Contracts

8

—

Discounted Cash flow

Average Historical Basis

-40% to 0%

Total Power

$

8

$

(9

)

Total PSEG

$

8

$

(9

)

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 )




	Quantitative Information About Level 3 Fair Value Measurements

								Significant
		Fair Value as of					Valuation	Unobservable
Commodity	Level 3 Position	December 31, 2017					Technique(s)	Input	Range
		Assets		(Liabilities)
		Millions
Power
Electricity	Electric Load Contracts	$	1	$	(3	)	Discounted Cash flow	Historic Load Variability	0% to 10%
Gas	Gas Physical Contracts	11		(2		)	Discounted Cash flow	Average Historical Basis	-40% to -10%
Total Power		$	12	$	(5	)
Total PSEG		$	12	$	(5	)


~~(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 Power is a seller, an increase in the load variability would decrease the fair value. For gas-related contracts in cases where Power is a buyer, an increase in the average historical basis would increase the fair value.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Table of Contents

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~~2018 and September 30, ~~2016,~~2017, respectively, follows:

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

for the Three Months andNine Months Ended September 30, ~~2017~~2018

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




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

	Nine Months Ended September 30, 2018
			Total Gains or (Losses) Realized/Unrealized
Description	Balance as of January 1, 2018		Included in Income (A)			Included in Regulatory Assets/ Liabilities (B)		Purchases (Sales)		Issuances/ Settlements (C)			Transfers In/Out (D)		Balance as of September 30, 2018
	Millions
PSEG
Net Derivative Assets (Liabilities)	$	7	$	(8	)	$	—	$	—	$	—		$	—	$	(1	)
Power
Net Derivative Assets (Liabilities)	$	7	$	(8	)	$	—	$	—	$	—		$	—	$	(1	)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Table of Contents

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

for the Three Monthsand Nine Months Ended September 30, ~~2016~~2017

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, 2017
				Total Gains or (Losses) Realized/Unrealized
Description	Balance as of July 1, 2017			Included in Income (E)		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 (E)		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

(A)

PSEG’s and Power’s ~~gains and losses~~gains(losses) attributable to changes in net derivative assets and liabilities ~~include $3 million and $29 million in Operating Income~~ for the three months and nine months ended September 30, ~~2017, respectively. The $3~~2018 include $(8) million and $(7) million, respectively, in Operating Revenues and $4 million and $(1) million, respectively, in Energy Costs. Both the $(8) million and $(7) million in Operating ~~Income is realized.~~Revenues are unrealized. Of the ~~$29~~$4 million and $(1) million in ~~Operating Income, $1~~Energy Costs, $5 million isand $(1) million are unrealized. Unrealized gains (losses) represent the change in derivative assets and liabilities still held at the end of the reporting period.


(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 and are expected to be recovered from/returned to PSE&G’s customers.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Table of Contents


(C)	Represents settlements of $(1) million for the three months ended September 30, 2018. Represents settlements of $(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~~

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(UNAUDITED)~~

~~Table of Contents~~

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

(D)

During the three months and nine months ended September 30, ~~2017~~2018, there were no transfers ~~in to~~into or out 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~~into or out of Level 3 during the three ~~months and nine~~ months ended September 30, ~~2016.~~2017.

(E)

PSEG’s and Power’s ~~gains and losses~~gains(losses) attributable to changes in net derivative assets and liabilities ~~include $8 million and $24 million in Operating Income~~ for the three months and nine months ended September 30, ~~2016, respectively. Of the $8~~2017 include $5 million and $22 million, respectively, in Operating Revenues and $(2) million and $7 million, respectively, in Energy Costs. The $5 million in Operating ~~Income, $4~~Revenues and $(2) million ~~is unrealized. The $24~~in Energy Costs for the three months ended September 30, 2017 are realized. Of the $22 million in Operating ~~Income is realized.~~Revenues and the $7 million in Energy Costs, $(2) million and $3 million, respectively, are unrealized for the nine months ended September 30, 2017.

As of September 30, ~~2017,~~2018, PSEG carried ~~$2.6~~$2.3 billion of net assets that are measured at fair value on a recurring basis, of which $6$1 million of net ~~assets were~~liabilities was measured using unobservable inputs and classified as Level 3 within the fair value hierarchy.

As of September 30, ~~2016~~2017, PSEG carried $2.6 billion of net assets that are measured at fair value on a recurring basis, of which ~~$11~~$6 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~~2018 and December 31, ~~2016~~2017.

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, 2018				December 31, 2017
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	Millions
Long-Term Debt:
PSEG (A) (B)	$	2,093	$	2,051	$	2,091	$	2,081
PSE&G (B)	9,182		9,292		8,591		9,322
Power (B)	3,084		3,254		2,386		2,659
Total Long-Term Debt	$	14,359	$	14,597	$	13,068	$	14,062

(A)

~~As of September 30, 2017, fair value includes a $700 million~~Includes floating rate term loan ~~in addition to the $500 million floating rate term loan and net offsets as~~ of ~~December 31, 2016.~~$700 million. The fair values of the term loan debt (Level 2 measurement) approximate the carrying values 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) 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.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Table of Contents

Note ~~13.~~14. Other Income ~~and Deductions~~(Deductions)

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




	PSE&G		Power			Other (A)			Consolidated
	Millions
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
Three Months Ended September 30, 2017
NDT Fund Interest and Dividends	$	—	$	12		$	—		$	12
Allowance for Funds Used During Construction	14		—			—			14
Solar Loan Interest	6		—			—			6
Other	2		(1		)	—			1
Total Other Income (Deductions)	$	22	$	11		$	—		$	33
Nine Months Ended September 30, 2017
NDT Fund Interest and Dividends	$	—	$	35		$	—		$	35
Allowance for Funds Used During Construction	42		—			—			42
Solar Loan Interest	16		—			—			16
Other	7		(1		)	(1		)	5
Total Other Income (Deductions)	$	65	$	34		$	(1	)	$	98


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

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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Table of Contents

Note ~~14.~~15. Income Taxes

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

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%




	Three Months Ended		Nine Months Ended
	September 30,		September 30,
	2018	2017	2018	2017
PSEG	22.1%	38.9%	25.1%	35.5%
PSE&G	25.5%	38.8%	26.1%	37.4%
Power	16.7%	41.9%	24.1%	37.9%

For the three months and nine months ended September 30, ~~2017,~~2018, the differences in PSEG’s effective tax rates as compared to the same periods in the prior year were due primarily to the change in the statutory federal tax rate from 35% to 21% as ~~well~~a result of the Tax Act and the remeasurement of uncertain tax positions and associated interest in connection with a 2015 claim to carry back tax-defined nuclear decommissioning costs under IRC 172(f) (nuclear carryback claim) and 2011 and 2012 federal tax audit, offset by the New Jersey (NJ) surtax, plant-related items and tax credits. For the three months and nine months ended September 30, 2018, the differences in PSEG’s effective tax rates as compared to the statutory tax rate of ~~40.85%,~~28.11% were due primarily to ~~changes in~~the remeasurement of uncertain tax positions and associated interest in connection with the ~~NDT Fund. For~~nuclear carryback claim and 2011 and 2012 federal tax audit, plant-related items and tax credits, offset by the ~~nine~~NJ surtax.

In August 2018, the IRS completed its audit of PSEG’s nuclear carryback claim and federal tax returns for the years 2011 and 2012. The completion of the IRS’ audit resulted in a settlement agreement with the IRS, which is subject to review by the Joint Committee on Taxation (JCT). As a result of this new information, PSEG remeasured certain unrecognized tax benefits that impacted the effective tax rate in the amount of $28 million, primarily related to the nuclear carryback claim and the associated interest, in the three months ended September 30, ~~2017, the effective tax rate was also favorably impacted by interest from a New Jersey State income tax refund.~~2018.

For the three months and nine months ended September 30, ~~2017,~~2018, the differences in PSE&G’s effective tax rates as compared to the same periods in the prior year were due primarily to the change in the statutory federal tax rate from 35% to 21% as ~~well~~a result of the Tax Act, offset by changes in uncertain tax positions, plant-related and other flow-through items. For the three months and nine months ended September 30, 2018, the differences in PSE&G’s effective tax rate as compared to the statutory tax rate of ~~40.85%,~~28.11% were due primarily to plant-related and other flow-through items, tax credits and changes in uncertain tax ~~positions, plant and other flow-through items.~~positions.

For the three months and nine months ended September 30, ~~2017,~~2018, the differences in Power’s effective tax rates as compared to the same periods in the prior year were due primarily to the change in the statutory federal tax rate from 35% to 21% as ~~well~~a result of the Tax Act and the remeasurement of uncertain tax positions and associated interest in connection with the nuclear carryback claim and 2011 and 2012 federal tax audit, offset by the NJ surtax. For the three months and nine months ended September 30, 2018, the differences in Power’s effective tax rates as compared to the statutory tax rate of ~~40.85%,~~28.11% were due primarily to ~~changes in~~the remeasurement of uncertain tax positions ~~manufacturing deduction~~ and associated interest in connection with the ~~NDT Fund.~~nuclear carryback claim and 2011 and 2012 federal tax audit, offset by the NJ surtax.

Uncertain Tax Positions

In August 2018, the IRS completed its audit of PSEG’s nuclear carryback claim and federal tax returns for the years 2011 and ~~2012~~2012. The JCT is required to review all claims over $5 million, and the tax years are ~~currently being audited by~~not considered concluded until the ~~IRS. The audit and other related claims are reasonably expected to be completed within the next 12 months.~~JCT’s review has been completed. As a result, it is reasonably possible that ~~a decrease in~~ PSEG’s total unrecognized tax benefits may ~~be necessary~~decrease in the range of ~~$80~~$50 million to ~~$180~~$120 million based on current ~~estimates.~~estimates within the next 12 months.

Tax Act

PSEG, PSE&G and Power recorded the impact of the Tax Act in their December 31, 2017 consolidated financial statements, including certain provisional amounts, in accordance with SEC guidance under Staff Accounting Bulletin 118 (SAB 118). PSEG’s accounting for certain elements of the Tax Act remains incomplete.

In August 2018, the IRS issued a Notice of Proposed Rulemaking (Notice) regarding the application of tax depreciation rules as amended by the Tax Act. In September 2018, PSEG recorded additional provisional adjustments thatincreased plant-related deferred taxes in the amount of $53 million and $35 million to the Regulatory Liability for the associated excess deferred taxes.PSEG continues to analyze the Notice and, as such, the amounts recorded for bonus depreciation for 2017 and 2018 remain provisional.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Table of Contents

Further, the Tax Act is unclear in certain respects and will require interpretations and implementing regulations by the IRS, as well as state tax authorities. The Tax Act could also be subject to potential amendments and technical corrections which could impact PSEG’s, PSE&G’s and Power’s financial statements.

The Protecting Americans from Tax Hikes Act of 2015 ~~(Tax~~(2015 Tax Act) ~~extended~~, among other provisions, included an extension of the ~~50%~~ bonus depreciation rules and the 30% investment tax credit for qualified property placed ininto service after 2016. Qualified property that is placed into service from January 1, 2015 through December 31, ~~2017. The rate~~2017 is ~~reduced to 40% and 30%~~eligible 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 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.depreciation. The provisions of the 2015 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~~have generated significant cash tax benefits for PSEG, PSE&G and Power through tax benefits related to the accelerated depreciation. ~~These~~

For the period beginning September 28, 2017, subject to the transition rules, the Tax Act modified the bonus depreciation rules of the 2015 Tax Act. Subject to further review of the Notice, it is expected that Power will be entitled to 100% expensing for qualifying 2018 plant additions and bonus depreciation will no longer apply to PSE&G.

New Jersey State Tax Reform

In July 2018, the State of New Jersey made significant changes to its income tax ~~benefits would have otherwise been received over~~laws, including imposing a temporary surtax on allocated corporate taxable income of 2.5% effective January 1, 2018 and 2019 and 1.5% in 2020 and 2021, as well as requiring corporate taxpayers to file in a combined reporting group as defined under New Jersey law starting in 2019. Both provisions include an ~~estimated average 20 year period. However,~~exemption for public utilities. At this time, 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. PSEG expects these new provisions to unfavorably affect its non-utility business. The newly enacted New Jersey tax ~~benefits will~~legislation did not have a ~~negative~~material impact on ~~the rate base of several of PSE&G’s programs.~~PSEG’s deferred income tax balance.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Table of Contents

Note ~~15.~~16. 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 )




PSEG	Other Comprehensive Income (Loss)
	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	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)
	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 Accumulative Other Comprehensive Income (Loss)	(1		)	22			(199		)	(178		)
Balance as of September 30, 2018	$	(1	)	$	(384	)	$	(22	)	$	(407	)

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	)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Table of Contents

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 )




Power	Other Comprehensive Income (Loss)
	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	)

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)
	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 Accumulative Other Comprehensive Income (Loss)	—		19			(194		)	(175		)
Balance as of September 30, 2018	$	—	$	(328	)	$	(19	)	$	(347	)

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	)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Table of Contents

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, 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) and OTTI	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	)

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		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
	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	$	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	Non-Operating Pension and OPEB Credits (Costs)	3			(1		)	2			7			(3		)	4
Amortization of Actuarial Loss	Non-Operating Pension and OPEB Credits (Costs)	(13		)	5			(8		)	(37		)	15			(22		)
Total Pension and OPEB Plans		(10		)	4			(6		)	(30		)	12			(18		)
Available-for-Sale Securities
Realized Gains (Losses) and OTTI	Net Gains (Losses) on Trust Investments	18			(10		)	8			71			(35		)	36
Total Available-for-Sale Securities		18			(10		)	8			71			(35		)	36
Total		$	10		$	(7	)	$	3		$	43		$	(24	)	$	19

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Table of Contents

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, 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) and OTTI	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	)

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 )




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
	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)	$	2		$	(1	)	$	1		$	6		$	(3	)	$	3
Amortization of Actuarial Loss	Non-Operating Pension and OPEB Credits (Costs)	(11		)	5			(6		)	(32		)	14			(18		)
Total Pension and OPEB Plans		(9		)	4			(5		)	(26		)	11			(15		)
Available-for-Sale Securities
Realized Gains (Losses) and OTTI	Net Gains (Losses) on Trust Investments	19			(10		)	9			62			(32		)	30
Total Available-for-Sale Securities		19			(10		)	9			62			(32		)	30
Total		$	10		$	(6	)	$	4		$	36		$	(21	)	$	15

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Table of Contents

Note ~~16.~~17. 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,
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




	Three Months Ended September 30,								Nine Months Ended September 30,
	2018				2017				2018				2017
	Basic		Diluted		Basic		Diluted		Basic		Diluted		Basic		Diluted
EPS Numerator (Millions):
Net Income	$	412	$	412	$	395	$	395	$	1,239	$	1,239	$	618	$	618
EPS Denominator (Millions):
Weighted Average Common Shares Outstanding	504		504		505		505		504		504		505		505
Effect of Stock Based Compensation Awards	—		3		—		2		—		3		��		2
Total Shares	504		507		505		507		504		507		505		507

EPS
Net Income	$	0.82	$	0.81	$	0.78	$	0.78	$	2.46	$	2.44	$	1.22	$	1.22

~~There were approximately 0.3 million for~~For the three months and nine months ended September 30, 2017, ~~and~~there were approximately ~~0.4~~0.3 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 2017 2016 2017 2016
Per Share $ 0.43
$ 0.41
$ 1.29
$ 1.23

In Millions $ 217
$ 207
$ 652
$ 622




	Three Months Ended				Nine Months Ended
	September 30,				September 30,
Dividend Payments on Common Stock	2018		2017		2018		2017
Per Share	$	0.45	$	0.43	$	1.35	$	1.29
In Millions	$	227	$	217	$	682	$	652

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Table of Contents

Note ~~17.~~18. 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		Power			Other (A)			Eliminations (B)			Consolidated Total
	Millions
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
Three Months Ended September 30, 2017
Total Operating Revenues	$	1,530	$	846		$	135		$	(257	)	$	2,254
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	$	4,749	$	3,033		$	334		$	(1,129	)	$	6,987
Net Income (Loss)	753		(131		)	(4		)	—			618
Gross Additions to Long-Lived Assets	2,118		903			25			—			3,046
As of September 30, 2018
Total Assets	$	30,694	$	12,681		$	2,249		$	(551	)	$	45,073
Investments in Equity Method Subsidiaries	—		88			—			—			88
As of December 31, 2017
Total Assets	$	28,554	$	12,418		$	2,666		$	(922	)	$	42,716
Investments in Equity Method Subsidiaries	—		87			—			—			87


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

(B)

Intercompany eliminations primarily relate ~~primarily~~ to intercompany transactions between PSE&G and 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 Power, see Note ~~18.~~19. Related-Party Transactions.

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(UNAUDITED)~~

~~Table of Contents~~

Note ~~18.~~19. 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 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




	Three Months Ended				Nine Months Ended
	September 30,				September 30,
Related-Party Transactions	2018		2017		2018		2017
	Millions
Billings from Affiliates:
Net Billings from Power primarily through BGS and BGSS (A)	$	229	$	259	$	1,079	$	1,154
Administrative Billings from Services (B)	78		82		246		226
Total Billings from Affiliates	$	307	$	341	$	1,325	$	1,380

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Table of Contents

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




	As of		As of
Related-Party Transactions	September 30, 2018		December 31, 2017
	Millions
Receivables from PSEG (C)	$	55	$	—
Payable to Power (A)	$	97	$	221
Payable to Services (B)	67		78
Payable to PSEG (C)	—		41
Accounts Payable—Affiliated Companies	$	164	$	340
Working Capital Advances to Services (D)	$	33	$	33
Long-Term Accrued Taxes Payable	$	67	$	91

Power

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

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

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(UNAUDITED)~~

~~Table of Contents~~




	Three Months Ended				Nine Months Ended
	September 30,				September 30,
Related-Party Transactions	2018		2017		2018		2017
	Millions
Billings to Affiliates:
Net Billings to PSE&G primarily through BGS and BGSS (A)	$	229	$	259	$	1,079	$	1,154
Billings from Affiliates:
Administrative Billings from Services (B)	$	38	$	39	$	113	$	117

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




	As of		As of
Related-Party Transactions	September 30, 2018		December 31, 2017
	Millions
Receivables from PSE&G (A)	$	97	$	221
Receivables from PSEG (C)	24		—
Accounts Receivable—Affiliated Companies	$	121	$	221
Payable to Services (B)	$	21	$	28
Payable to PSEG (C)	—		29
Accounts Payable—Affiliated Companies	$	21	$	57
Short-Term Loan to (from) Affiliate (E)	$	119	$	(281	)
Working Capital Advances to Services (D)	$	17	$	17
Long-Term Accrued Taxes Payable	$	1	$	52

(A)

PSE&G has entered into a requirements contract with Power under which Power provides the gas supply services needed to meet PSE&G’s BGSS and other contractual requirements. Power has also entered into contracts to supply energy, capacity and ancillary services to PSE&G through the BGS auction process. The rates in the BGS and BGSS contracts are prescribed by the BPU. In addition, 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 Power at cost. In addition, PSE&G and 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 Power have advanced working capital to Services. The amounts are included in Other Noncurrent Assets on PSE&G’s and Power’s Condensed Consolidated Balance Sheets.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Table of Contents


(E)	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)~~

~~Table of Contents~~

Note ~~19.~~20. Guarantees of Debt

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 Power’s non-guarantor subsidiaries, as of September 30, ~~2017~~2018 and December 31, ~~2016~~2017 and for the three months and nine months ended September 30, ~~2017~~2018 and ~~2016.~~2017.

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 )




	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

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Table of Contents

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 )




	Power			Guarantor Subsidiaries			Other Subsidiaries			Consolidating Adjustments			Total
	Millions
Three Months Ended September 30, 2017
Operating Revenues	$	—		$	829		$	46		$	(29	)	$	846
Operating Expenses	2			618			44			(29		)	635
Operating Income (Loss)	(2		)	211			2			—			211
Equity Earnings (Losses) of Subsidiaries	143			(3		)	3			(140		)	3
Net Gains (Losses) on Trust Investments	—			19			—			—			19
Other Income (Deductions)	24			26			(2		)	(37		)	11
Non-Operating Pension and OPEB Credits (Costs)	—			2			—			—			2
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	$	—		$	2,983		$	145		$	(95	)	$	3,033
Operating Expenses	4			3,268			139			(95		)	3,316
Operating Income (Loss)	(4		)	(285		)	6			—			(283		)
Equity Earnings (Losses) of Subsidiaries	(111		)	(8		)	11			119			11
Net Gains (Losses) on Trust Investments	3			59			—			—			62
Other Income (Deductions)	67			66			—			(99		)	34
Non-Operating Pension and OPEB Credits (Costs)	—			6			—			—			6
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	)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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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




	Power		Guarantor Subsidiaries		Other Subsidiaries		Consolidating Adjustments			Total
	Millions
As of September 30, 2018
Current Assets	$	4,497	$	1,353	$	302	$	(4,776	)	$	1,376
Property, Plant and Equipment, net	55		5,074		3,740		—			8,869
Investment in Subsidiaries	5,086		1,124		—		(6,210		)	—
Noncurrent Assets	245		2,302		106		(217		)	2,436
Total Assets	$	9,883	$	9,853	$	4,148	$	(11,203	)	$	12,681
Current Liabilities	$	616	$	3,030	$	1,999	$	(4,776	)	$	869
Noncurrent Liabilities	466		2,129		633		(217		)	3,011
Long-Term Debt	2,834		—		—		—			2,834
Member’s Equity	5,967		4,694		1,516		(6,210		)	5,967
Total Liabilities and Member’s Equity	$	9,883	$	9,853	$	4,148	$	(11,203	)	$	12,681
As of December 31, 2017
Current Assets	$	4,327	$	1,500	$	200	$	(4,686	)	$	1,341
Property, Plant and Equipment, net	54		5,778		2,764		—			8,596
Investment in Subsidiaries	4,844		404		—		(5,248		)	—
Noncurrent Assets	100		2,349		110		(78		)	2,481
Total Assets	$	9,325	$	10,031	$	3,074	$	(10,012	)	$	12,418
Current Liabilities	$	689	$	3,586	$	1,846	$	(4,686	)	$	1,435
Noncurrent Liabilities	533		1,966		459		(78		)	2,880
Long-Term Debt	2,136		—		—		—			2,136
Member’s Equity	5,967		4,479		769		(5,248		)	5,967
Total Liabilities and Member’s Equity	$	9,325	$	10,031	$	3,074	$	(10,012	)	$	12,418

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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). Information contained herein relating to any individual company is filed by such company on its own behalf. PSE&G and 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.

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~~2017 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~~2017 and Future Outlook provided in Item 7 in our Form 10-K by describing significant events and business developments that have occurred during ~~2017~~2018 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~~2017 Form 10-K.

EXECUTIVE OVERVIEW OF ~~2017~~2018 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~~investing capital in T&D ~~and other~~ infrastructure projects ~~designed to~~that enhance system reliability and resiliency, and clean energy projects to meet customer expectations and support public policy ~~objectives,~~

objectives. Over the past few years, our investments have altered our business mix to reflect a higher percentage of earnings contribution by PSE&G. Over the next five years, we expect to invest between $12 billion and $16 billion in our business which is expected to provide an annual rate base growth of 8%—10%. We have completed our Energy Strong Program I (ES I) and are forecasting completion of our Gas System Modernization Program I (GSMP I) early next year.

~~maintaining~~In May 2018, we received approval for the Gas System Modernization Program II (GSMP II), an expanded, five-year program to invest $1.9 billion over five years 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 mix~~future base rate case. As part of ~~fuels which allows us~~the settlement, PSE&G agreed to ~~respond~~file a base rate case no later than five years from the commencement of the program, to ~~market volatility~~maintain a base level of gas distribution capital expenditures of $155 million per year and ~~capitalize on opportunities~~to achieve certain leak reduction targets.

In June 2018, we filed for our Energy Strong Program II (ES II), a proposed five-year $2.5 billion program to harden, modernize and make our electric and gas distribution systems more resilient. The size and duration of ES II, as ~~they arise.~~

well as certain other elements of the program, are subject to BPU approval.

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In October 2018, we filed our proposed Clean Energy Future (CEF) program with the BPU, a six-year estimated $3.6 billion investment program focused on achieving New Jersey’s energy efficiency targets, supporting electric vehicle infrastructure, deploying energy storage, and implementing an Energy Cloud program which will include installing 2.2 million advanced meter infrastructure (AMI) smart meters and associated infrastructure.

Also, in October 2018, the BPU issued an Order approving the settlement of our distribution base rate case with new rates effective November 1, 2018. The settlement resulted in a net reduction in overall annual revenues of approximately $13 million, comprised of a $212 million increase in base revenues, which includes the recovery of deferred storm costs, and the return of tax benefits largely due to tax reform of approximately $225 million. The Order provides for a distribution rate base of $9.5 billion, a 9.6% return on equity (ROE) for our distribution business and a 54% equity component of our capitalization structure. In addition to the $13 million annual revenue reduction, the Order provides for a one-time refund for taxes collected at the higher federal income tax rate for the January 1 to March 31, 2018 period. As a result, PSE&G will refund $28 million to customers in November and December 2018.

Power

At 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. Power continues to move its fleet towards improved efficiency and believes that its 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. Power’s hedging practices and ability to capitalize on market opportunities help it to balance some of the volatility of the merchant power business. More than half of Power’s expected gross margin in 2018 relates to our hedging strategy, our expected revenues from the capacity market mechanisms and certain ancillary service payments such as reactive power.

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 additions to our fleet both expand our geographic diversity and adjust our fuel mix and are expected to enhance the environmental profile and overall efficiency of Power’s generation fleet.

Financial Results

The results for PSEG, PSE&G and Power for the three months and nine months ended September 30, ~~2017~~2018 and ~~2016~~2017 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)	2018		2017		2018		2017
	Millions
PSE&G	$	278	$	246	$	828	$	753
Power (A)	125		136		400		(131		)
Other (B)	9		13		11		(4		)
PSEG Net Income	$	412	$	395	$	1,239	$	618

PSEG Net Income Per Share (Diluted)	$	0.81	$	0.78	$	2.44	$	1.22

(A)

Includes after-tax expenses of $5 million and $568 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~~ related to the early retirement of Power’s Hudson and Mercer coal/gas generation plants. See Item 1. Note 3.4. Early Plant Retirements 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 ~~of $45 million for the nine months ended September 30, 2017, 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.~~leases of $14 million and $45 million in the nine months ended September 30, 2018 and 2017, respectively. See Item 1. Note 6.7. Financing Receivables for additional information.

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.

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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,
	2018			2017			2018			2017
	Millions, after tax
NDT Fund Income (Expense) (A) (B)	$	27		$	10		$	16		$	32
Non-Trading MTM Gains (Losses) (C)	$	(96	)	$	(27	)	$	(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 8. 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 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, $(37)~~$(16) million and $0$(12) million for the three months and $(12) million and $(37) million for the nine months ended September 30, ~~2017~~2018 and ~~2016,~~2017, respectively.


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

Our ~~$68~~$17 million increase in Net Income for the three months ended September 30, ~~2017~~2018 was driven ~~primarily~~largely by

~~an impairment~~higher earnings due to continued investment in ~~2016 related to investments~~transmission and distribution clause programs,

the favorable impact at Power from the lower federal tax rate effective January 1, 2018 and remeasurement of uncertain tax positions and associated interest in ~~certain leveraged leases at Energy Holdings,~~connection with the nuclear carryback claim and 2011 and 2012 federal tax audit, and

higher ~~charges~~volumes of electricity sold in ~~2016~~the PJM region generated by our new Keys and Sewaren combined cycle facilities,

largely offset by higher MTM net losses in 2018, and

higher generation costs driven by increased volumes of gas purchased at higher average prices in the PJM region.

Our $621 million increase in Net Income for the nine months ended September 30, 2018 was driven largely by

accelerated depreciation in 2017 related to early retirement of our Hudson and Mercer coal/gas generation units,

the favorable impact at Power

from the lower ~~generation costs driven by lower natural gas costs~~federal tax rate effective January 1, 2018 and ~~congestion costs,~~remeasurement of uncertain tax positions and associated interest in connection with the nuclear carryback claim and 2011 and 2012 federal tax audit,

higher earnings due to continued investment in transmission ~~revenues.~~and distribution clause programs,

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~~These favorable variances were partially offset by~~

~~lower sales~~higher volumes of electricity sold under wholesale load contracts in the ~~Basic Generation Service contract~~PJM region, and ~~in PJM, and~~

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

Our $367 million decrease in Net Income for the nine months ended September 30, 2017 was driven largely by higher charges, primarily accelerated depreciation, related to the early retirement of our Hudson and Mercer coal/gas generation units at Power. These decreases were partially offset by

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

lower charges in 2018 related to leveraged lease investments ~~in certain leveraged leases at Energy Holdings,~~(see Item 1. Note 7. Financing Receivables),

partially offset by MTM losses in ~~2016, and~~2018,

higher ~~NDT gains~~ fuel generation costs,

and lower ~~NDT losses in 2017.~~volumes of electricity sold at lower prices under our BGS contracts.

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 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 focus has been to invest 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 to invest in transmission projects that focus on reliability improvements and replacement of aging infrastructure, including our $275 million Newark Switch project that was approved by PJM in July 2017. We also continue to make investments to improve 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 and nine months of forecasted data updated for actual data throughout the proceeding. The distribution base rate case will provide PSE&G the opportunity 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 of our Energy Efficiency program.

Although 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 needs of our utility customers and generating units.

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~~Power’s hedging practices~~approach to managing our company. We continue our focus on operational excellence, financial strength and ~~ability~~disciplined investment. These guiding principles have provided the base from which we have been able to ~~capitalize on market~~execute our strategic initiatives.

Operational Excellence

We emphasize operational performance while developing opportunities ~~help~~in both our competitive and regulated businesses. Flexibility in our generating fleet has allowed us to take advantage of opportunities in a rapidly evolving market as we remain diligent in managing costs. For the first nine months of 2018, our

utility achieved continued strong reliability and customer satisfaction results, as well as comprehensive storm preparation and restoration efforts, and ongoing cost control,

diverse fuel mix and dispatch flexibility allowed us to generate approximately 42 terawatt hours while addressing fuel availability and price volatility, and

total nuclear fleet achieved a capacity factor of 92.9%.

Financial Strength

Our financial strength is predicated on a solid balance ~~some~~sheet, positive operating cash flow and reasonable risk-adjusted returns on increased investment. Our financial position remained strong during the first nine months of 2018 as we

maintained sufficient liquidity,

maintained solid investment grade credit ratings, and

increased our indicative annual dividend for 2018 to $1.80 per share.

We expect to be able to fund our planned capital requirements and manage the impacts of the ~~volatility~~Tax Act without the issuance of new equity. For additional information on the impacts of the ~~merchant power business. Power’s hedging program~~Tax Act, see Item 1. Note 6. Rate Filings and Note 15. Income Taxes.

Disciplined Investment

We utilize rigorous investment criteria when deploying capital and seek to invest in ~~combination~~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 ~~expected revenues from~~growing demand. In the ~~capacity market mechanisms and certain ancillary service payments, such as reactive power, has secured approximately 60%~~first nine months of ~~its estimated gross margin for the 2017-2019 period.~~2018, we

~~Our~~made additional investments in ~~Keys~~T&D infrastructure projects,

continued to execute our GSMP I, Energy ~~Center (Keys),~~Efficiency and other existing BPU-approved utility programs,

received approval for our GSMP II program and filed our proposed ES II and CEF programs, and

commenced commercial operation of 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 natural gas prices driven by the growth of shale gas production since 2007, the continuing cost of regulatory compliance and enhanced security for nuclearKeys generation 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 revenuescontinued construction of ~~nuclear generating stations while limiting their ability to reduce the unit cost of production. This may result~~our BH5 generation project, which is targeted for commercial operation 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.mid-2019.

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~~ For additional information about regulatory, legislative and other developments that may affect the company, see Part I, Item 1. Regulatory Issues in our 2017 ~~the PJM Board announced that it would be lifting the previously disclosed suspension of the Artificial Island transmission project~~Annual Report on 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 Forms 10-Q for the Artificial Island project. In October 2017, FERC accepted PJM’s filing 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 decideperiods ending March 31, 2018 and June 30, 2018 and 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 (D.C. 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~~

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~~service (BGS)~~BGS supplier, 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 Power’s business or results of operations.

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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).~~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 existing ROE is unjust and unreasonable, 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 the RPM capacity auction for the 2020-2021 delivery year. Power cleared approximately 7,800 MW 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~~various 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.models. We are ~~currently awaiting FERC action on~~still analyzing the ~~suppliers’ request~~potential impact of these methodologies and cannot predict the outcome of ~~the~~this proceeding. See Part II, Item 5. Other Information for additional information.

Wholesale Power Market Design

In June ~~2017, PJM~~2018, FERC issued an ~~energy~~order finding that PJM’s current capacity market is unjust and unreasonable because it allows resources supported by out-of-market payments to suppress capacity prices. FERC established a proceeding to consider an alternative capacity market design. FERC’s potential action in this proceeding could cause nuclear units that receive zero emissions certificates (ZEC) payments to lose capacity market revenues if states do not take steps to address this potential loss of capacity revenues. In addition, depending on the outcome of this matter, our fossil generating stations could also be impacted. We cannot predict the outcome of this matter.

The PJM Board directed PJM staff to work with stakeholders to implement a series of price formation ~~proposal~~reforms, including a 30-minute reserve product in real-time, more dynamic reserve requirements to ~~address a flaw~~better capture operator actions taken to maintain reliability, and improvement to the curves used to price reserves during reserve shortage conditions. The PJM Board letter directs PJM staff to submit some of these reforms for FERC’s approval so that they can be implemented 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.early 2019. If placed into effect, ~~this proposal will~~these reforms should improve ~~price formation~~energy and reserve prices by ensuring that when operators commit resources to ensure reliability, the ~~marginal costs of units serving load will be better~~commitments are reflected in market clearing prices. We cannot predict the outcome of this matter.

Distribution

~~In June 2017, the~~The BPU ~~issued proposed~~has enacted Infrastructure Investment Program (IIP) regulations that ~~would~~ allow utilities to construct, install, or remediate utility plant and facilities related to reliability, resiliency, and/or safety to support the provision of safe and adequate service. Under ~~the proposed~~these regulations, utilities ~~could~~can seek authority to make specified infrastructure investments in programs extending for up to five years with accelerated cost recovery mechanisms. The BPU characterized the IIP regulations as a regulatory initiative intended to create a financial incentive for utilities to accelerate the level of investment needed to promote the timely rehabilitation and replacement of certain ~~non-revenue producing~~traditional utility infrastructure that enhances reliability, resiliency, and/or safety. ~~The proposed regulations will be subject to comment from interested parties.~~

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~~August 2018, the EPA ~~to review~~released the ~~New Source Performance Standards, which establish emissions standards~~proposed Affordable Clean Energy (ACE) rule as a replacement for CO₂ ~~for certain new fossil power plants, and~~ the EPA’s Clean Power ~~Plan (CPP),~~Plan. The proposed ACE rule gives states great flexibility to evaluate specific heat rate improvement technologies and practices to be applied at coal-fired electric generating units. States have three years from the date of finalization to submit a ~~greenhouse gas emissions regulation under the Clean Air Act for existing power plants~~plan that establishes ~~state-specific emission rate targets based on implementation~~a standard of performance that reflects the ~~best system~~degree of emission ~~reduction. In October 2017,~~limitation through the ~~EPA Administrator signed a proposed repeal~~application 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

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~~generating units). Whether the EPA chooses to propose a replacement rule has not been decided. PSEG~~heat rate improvement technologies and practices. We cannot estimate the impact of ~~these actions~~this action on our business ~~and future~~or results of operations at this time.

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

For further information regarding the matters described above, as well as other matters that may impact our financial condition and results of operations, see Item 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 9.10. Commitments and Contingent Liabilities.

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Early ~~Retirement of Hudson and Mercer Units~~Plant Retirements

Fossil

On June 1, 2017, Power completed its previously announced retirement of the generation operations of the existing coal/gas units at the Hudson and Mercer generating stations. The decision to retire the Hudson and Mercer units had a material effect on PSEG’s and Power’s results 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 Expense 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 3.4. Early Plant Retirements for additional information.

Power ~~currently anticipates~~is exploring various opportunities with these sites, including using the sites for alternative industrial ~~activity. However, if~~activity or the

disposition of one or both of the sites. 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 the end of their designated useful lives and their continued classification as held for use. The precise timing of a change 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 Power’s future financial results.

~~Leveraged Lease Portfolio~~Nuclear

~~GenOn Energy, Inc. (GenOn), the parent company of REMA, and certain of its subsidiaries filed voluntary petitions for relief under Chapter 11 of~~Since 2013, several nuclear generating stations in the United States ~~Bankruptcy Code on June 14, 2017. REMA was not included~~have closed or announced early retirement due to economic reasons, or have announced being at risk for early retirement. In September 2018, Exelon, a co-owner of the Salem units, shut down its Oyster Creek nuclear plant located in New Jersey one year earlier than previously planned for economic reasons. In addition, First Energy announced in March 2018 the early retirement of four nuclear units at the Davis-Besse, Perry Nuclear and Beaver Valley nuclear plants in Ohio and Pennsylvania by 2021. These closures and retirements are generally due to the decline 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, both federal and state-level policies that provide financial incentives to construct renewable energy such as wind and solar and the failure to adequately compensate nuclear generating stations for the attributes they bring similar to renewable energy production. 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 ~~GenOn bankruptcy filing. GenOn is currently engaged~~electric generation industry experiencing a further shift from nuclear generation to natural gas-fired generation, creating less diversity of the generation fleet.

In May 2018, the governor of New Jersey signed legislation that would provide a safety net in order to prevent the loss of environmental attributes from selected nuclear generating stations referred to as the ZEC program. The legislation calls for the BPU to establish a ~~balance sheet restructuring, which~~collection process for a customer charge, determine eligibility and certification of need, and potentially select nuclear plants to receive ZECs starting in April 2019. The law mandates each New Jersey electric distribution company, including PSE&G, to purchase ZECs and recover its procurement of ZECs through a non-bypassable charge (ZEC charge) in the amount of $0.004 per kilowatt-hour.

In the ordinary course, management, and in the case of the Salem units the co-owner, each makes a number of decisions that impact the operation of our nuclear units beyond the current year, including whether and to what extent these units participate in Reliability Pricing Model capacity auctions, commitments relating to refueling outages and significant capital expenditures, and decisions regarding our hedging arrangements. When considering whether to make these future commitments, management’s decisions will ~~take an undetermined time~~primarily be influenced by the financial outlook of the units, including the progress, timing and continued outlook for selection of the units under the newly enacted legislation in the state of New Jersey. Power and Exelon have agreed 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~~assess and, when appropriate, approve the ~~restructuring~~funding of ~~GenOn~~individual capital projects to ensure compliance with regulatory requirements and the ~~possible related impact on REMA~~safe operation of the Salem generating station and that the funding of previously postponed projects may be restored as a result of the legislation enacted in New Jersey sufficiently values the attributes of nuclear generation and Salem benefits from such legislation.

Power believes it may be unable to cover its costs and would be inadequately compensated for its market and operational risks at the Salem and Hope Creek nuclear units, which would result in Power retiring these units early, if (i) energy market prices continue to ~~discuss~~be depressed, (ii) there are adverse impacts from potential changes to the ~~situation~~capacity market construct being considered by FERC, or (iii) Salem and/or Hope Creek are not selected to participate in the ZEC program or the ZEC program does not adequately compensate our nuclear generating stations for their attributes. The costs associated with ~~GenOn.~~

~~During~~any such retirement, which may include, among other things, accelerated depreciation and amortization or impairment charges, accelerated asset retirement costs, severance costs, environmental remediation costs and additional funding of the ~~first quarter of 2017, due~~NDT Fund would be material to ~~continuing liquidity issues facing REMA, economic challenges facing coal generation in PJM,~~both PSEG 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 leveragedPower. If

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~~lease receivables, which was reflected~~any or all of the Salem and Hope Creek units were shut down, it would significantly alter New Jersey’s energy supply predominately by increasing New Jersey’s reliance on natural gas generation. Such a decrease in ~~Operating Revenues. During~~fuel diversity could also increase the ~~second quarter~~market’s vulnerability to price fluctuations and power disruptions in times of ~~2017,~~high demand.

Leveraged Leases

In September 2018, certain subsidiaries of Energy Holdings ~~recorded~~(PSEG Entities) entered into a Restructuring Support Agreement (RSA) with REMA. Pursuant to the RSA, the PSEG Entities have agreed to support the implementation of restructuring and related transactions with respect to REMA’s indebtedness. Such restructuring transactions will be implemented by REMA on an ~~additional $22 million pre-tax charge for its current best estimate~~in-court basis under Chapter 11 of ~~loss related~~the Bankruptcy Code. The RSA outlines a plan of reorganization under which, in addition to ~~lease receivables due~~other terms, the ownership interest in the leases relating to ~~collectability of payments ($15 million)~~the Keystone and ~~economics impacting the residual value ($7 million)~~Conemaugh investments will be transferred to holders of certain ~~leased assets.~~debtholders of REMA. Upon consummation of the restructuring transactions, the PSEG ~~continues~~Entities will receive $31.5 million in cash in exchange for (a) the full satisfaction of all claims asserted against REMA and (b) approval of certain amendments to ~~monitor any~~the Shawville lease. The Shawville lease amendments, among other things, will allow REMA to express tentative interest in a renewal on or after November 24, 2019, with similar changes to ~~REMA’s~~the other milestones in the lease renewal procedures. In addition, REMA has agreed to fund qualifying credit support up to $36 million. Energy Holdings will be required upon resolution of this matter to accelerate and ~~GenOn’s status~~pay approximately $40 million of state deferred tax liabilities and ~~potential impacts on Energy Holdings’ lease investments, which could include further write-downs~~accelerate and pay and/or reduce $85 million of a forecasted federal tax loss to the values 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 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.Internal Revenue Service.

Additional facilities in our leveraged lease portfolio include the 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.

Tax Legislation

In December 2017, the U.S. government enacted comprehensive tax legislation (Tax Act), which, 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 bonus depreciation rules.

As a result of the enacted reduction in the statutory U.S. corporate income tax rate, as well as other aspects of the Tax Act, in December 2017 PSE&G recorded excess deferred taxes of approximately $2.1 billion and recorded an approximate $2.9 billion revenue impact of these excess deferred taxes as Regulatory Liabilities.

Beginning in 2018, PSEG, on a consolidated basis, is incurring lower income tax expense resulting in a decrease in its projected effective income tax rate. This has increased PSEG’s and Power’s net income. To the extent allowed under the Tax Act, Power’s operating cash flows will reflect the full expensing of capital investments for income tax purposes. PSEG and Power expect that the interest on their debt will continue to be fully tax deductible albeit at a lower tax rate. For PSE&G, the Tax Act has led to lower customer rates due to lower income tax expense recoveries and the BPU has approved our proposal 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 case 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 August 2018, the Internal Revenue Service issued a Notice of Proposed Rulemaking (Notice) regarding the application of tax depreciation rules as amended by the Tax Act. While the Notice provides some guidance as to the application of the changes made by the Tax Act to the bonus depreciation rules, certain aspects still remain unclear. Until clarity is provided, the amounts recorded for bonus depreciation for 2017 and 2018 remain provisional and are based on a reasonable interpretation of the Notice.

The impact of the Tax Act may differ from these estimates, possibly materially, due to, among other things, changes in interpretations and assumptions PSEG has made, guidance that may be issued and actions PSEG may take as a result of the Tax Act. For additional information, see Item 1. Note 15. Income Taxes.

As a result of the enactment of the Tax Act, various state regulatory authorities, including the BPU, have taken action to ensure that excess federal income taxes previously collected in rates are returned to customers. We have made filings to adjust the revenue requirement in certain of our rate matters as a result of the change in the federal income tax rate.

In addition, FERC continues to assess whether, and if so how, it will address changes and flow-backs to customers relating to accumulated deferred income taxes and bonus depreciation. See Item 1. Note 6. Rate Filings for additional information.

In July 2018, the State of New Jersey made significant changes to its income tax laws, including imposing a temporary surtax on allocated corporate taxable income of 2.5% effective January 1, 2018 and 2019 and 1.5% in 2020 and 2021, as well as

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~~Salem~~

~~Concurrently~~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 non-utility business. In accordance with ~~the planned refueling outage~~GAAP accounting for income taxes, deferred taxes are required to be measured at the ~~Salem 2 unit that was conducted~~enacted tax rate expected to apply to taxable income in the ~~second quarter of 2017, we inspected and replaced baffle bolts as part of our strategy~~periods in which the deferred taxes are expected to ~~replace baffle bolts at the Salem station.~~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

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

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

advocate for 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,

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~~In addition to the risks describe elsewhere in this Form 10-Q and our Form 10-K for the year ended December 31, 2017, for 2018 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~~proceedings,

applying 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 select our ~~distribution base rate case proceeding~~New Jersey nuclear generation units to ~~be filed in 2017,~~receive payments under the ZEC program,

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, in each case 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,

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~~continued or expanded participation in solar, energy efficiency and related programs,~~ 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.

Power has stopped taking new customers in its retail energy business. Power will continue to meet all of its obligations to our existing customers through the end of their current contracts.

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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 Power, excluding charges related to intercompany transactions, which are eliminated in consolidation. For additional information on intercompany transactions, see Item 1. Note ~~18.~~19. 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)
	2018		2017		2018 vs. 2017					2018		2017		2018 vs. 2017
	Millions				Millions			%		Millions				Millions			%
Operating Revenues	$	2,394	$	2,254	$	140		6		$	7,228	$	6,987	$	241		3
Energy Costs	804		616		188			31		2,356		2,072		284			14
Operation and Maintenance	742		693		49			7		2,221		2,128		93			4
Depreciation and Amortization	294		252		42			17		854		1,721		(867		)	(50	)
Income from Equity Method Investments	5		3		2			67		12		11		1			9
Net Gains (Losses) on Trust Investments	45		18		27			N/A		31		71		(40		)	(56	)
Other Income (Deductions)	33		33		—			—		99		98		1			1
Non-Operating Pension and OPEB Credits (Costs)	19		—		19			N/A		57		1		56			N/A
Interest Expense	127		100		27			27		341		289		52			18
Income Tax Expense	117		252		(135		)	(54	)	416		340		76			22

The following discussions for PSE&G and 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)
	2018		2017			2018 vs. 2017					2018		2017			2018 vs. 2017
	Millions					Millions			%		Millions					Millions			%
Operating Revenues	$	1,595	$	1,530		$	65		4		$	4,826	$	4,749		$	77		2
Energy Costs	593		543			50			9		1,863		1,793			70			4
Operation and Maintenance	389		357			32			9		1,133		1,086			47			4
Depreciation and Amortization	192		169			23			14		569		506			63			12
Net Gains (Losses) on Trust Investments	—		—			—			N/A		—		2			(2		)	N/A
Other Income (Deductions)	21		22			(1		)	(5	)	61		65			(4		)	(6	)
Non-Operating Pension and OPEB Credits (Costs)	14		(2		)	16			N/A		44		(5		)	49			N/A
Interest Expense	83		79			4			5		246		223			23			10
Income Tax Expense	95		156			(61		)	(39	)	292		450			(158		)	(35	)

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

Operating Revenues ~~decreased $175~~increased $65 million due to changes in delivery, commodity, clause and other operating revenues.

Table of Contents

Delivery Revenues increased $8 million due primarily to

Transmission, electric distribution and gas distribution revenue requirements were $78 million lower as a result of rate reductions due to the Tax Act which reduced the corporate income tax rate. This decrease is offset in Income Tax Expense.

Gas distribution revenues decreased $1 million due primarily to a $2 million decrease from lower sales volumes and a $1 million decrease from ES I investments, partially offset by a $2 million increase from the inclusion of the GSMP I in base rates.

Electric distribution revenues increased $45 million due to $33 million in higher sales volumes, a $10 million increase from higher ES I investments in base rates and higher Green Program Recovery Charges (GPRC) of $2 million.

Transmission revenues were $42 million higher due to revenue requirements calculated through our transmission formula rate, primarily to recover increased investments.

Commodity Revenues increased $50 million as a result of higher Electric and Gas revenues. The changes in Commodity revenues 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 basic gas supply service (BGSS) to retail customers.

Electric commodity revenues increased $47 million due to $79 million in higher BGS sales volumes, partially offset by $32 million from lower BGS prices.

Gas commodity revenues increased $3 million due primarily to higher BGSS sales prices of $4 million, partially offset by lower BGSS sales volumes of $1 million.

Clause Revenues increased $5 million due primarily to higher collections of Societal Benefit Charges (SBC) of $6 million and a $5 million increase in Margin Adjustment Clause (MAC) revenues, partially offset by a $7 million decrease in collections of GPRC. The changes in the SBC, MAC and GPRC 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 SBC, MAC or GPRC collections.

Operating Expenses

Energy Costs increased. This is entirely offset by the change in Commodity Revenues.

Operation and Maintenance increased $32 million due primarily to increases of $7 million in clause and renewable related net expenditures, $7 million in distribution maintenance, $6 million in transmission maintenance, $5 million in injuries and damages and $4 million in appliance service costs.

Depreciation and Amortization increased $23 million due primarily to an increase in ~~transmission~~depreciation due to additional plant placed into service.

Non-Operating Pension and OPEB Credits (Costs) reflected an increase of $16 millionin creditsdue to the adoption of new accounting guidance effective January 1, 2018 which no longer allows capitalization of any portion of these benefit costs. See Item 1. Note 2. Recent Accounting Standards.

Interest Expense increased $4 million due primarily to $6 million related to net debt issuances in May and September 2018 and December 2017, partially offset by a reduction of $1 million related to clauses.

Income Tax Expense decreased $61 million due primarily to the decrease in the federal statutory income tax rate from 35% in 2017 to 21% in 2018.

Nine Months Ended September 30, 2018 as Compared to 2017

Operating Revenues increased $77 million due to changes in delivery, commodity, clause and other operating revenues.

Delivery Revenues increased $9 million due primarily to

Transmission, electric distribution and gas distribution revenue requirements were $207 million lower as a result of rate reductions due to the Tax Act which reduced the corporate income tax rate. This decrease is offset in Income Tax Expense.

Transmission revenues were ~~$34~~$122 million higher due to higher revenue requirements calculated through our transmission formula rate, primarily to recover ~~required~~increased investments.

~~Gas~~Electric distribution revenues increased $5$52 million due to $36 million in higher sales volumes and a $1$16 million increase from the inclusion of ~~Energy Strong~~increased ES I investments in base ~~rates, and $1~~rates.

Table of Contents

Gas distribution revenues increased $42 million ~~increases in both GSMP collections and Green Program Recovery Charges (GPRC) and~~due primarily to a $44 million increase due to higher sales ~~volumes.~~

~~Electric distribution revenues decreased $29 million due to~~volumes, a ~~$38 million decrease due to lower sales volumes and lower GPRC of $6 million, partially offset by a $15~~$24 million increase from the inclusion of ~~Energy Strong~~the GSMP I in base ~~rates.~~rates and a $3 million increase in GPRC collections. These increases were partially offset by a $29 million decrease in WNC collections.

Commodity ~~Revenue~~Revenues ~~decreased $186~~increased $70 million as a result of ~~lower~~higher Electric ~~and~~revenues partially offset by lower Gas revenues. The changes in Commodity ~~revenue~~revenues 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 $176~~increased $77 million due primarily to $127 million in higher BGS sales volumes and a ~~$153~~$3 million ~~decrease in BGS revenues due to $97~~increase from sales of solar renewable energy credits, partially offset by $53 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).~~BGS prices.

Gas commodity revenues decreased ~~$10~~$7 million due to lower BGSS ~~sales~~ prices of ~~$22~~$47 million, partially offset by higher BGSS sales volumes of ~~$12~~$40 million.

Clause Revenues ~~increased $1~~decreased $7 million due ~~primarily~~ to ~~the return of $20~~a $6 million ~~to customers~~decrease in ~~2016 of overcollections of Securitization Transition Charges (STC), partially offset by lower Societal Benefit Charges (SBC) of $12 million~~MAC revenues and a $6 million decrease in ~~2017~~GPRC. These decreases were partially offset by higher SBC collections of $4 million and a $1 million increase in ~~Margin Adjustment Clause (MAC) revenues.~~collections of Solar Pilot Recovery Charges (SPRC). The changes in the ~~STC,~~MAC, GPRC, SBC and ~~MAC~~SPRC 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, GPRC, SBC or ~~MAC~~SPRC collections.

Other Operating Revenues increased $5 million due primarily to an increase in appliance service revenues.

Operating Expenses

Energy Costs ~~decreased $186~~increased $70 million. This is entirely offset by the change in Commodity ~~Revenue.~~Revenues.

Operation and Maintenance ~~decreased $30~~increased $47 million, due primarily ~~due~~ to ~~a $17 million reduction in clause-related costs, $6~~increases of $13 million in ~~lower~~transmission maintenance, $12 million in appliance service costs, $6$9 million ~~of lower~~in storm costs, $9 million in distribution ~~corrective and preventative~~ maintenance and ~~a $5~~$7 million ~~reduction~~ in ~~GPRC related costs,~~the gas distribution tariff. These increases were partially offset by a net ~~increase of~~ $4 million decrease in ~~certain operational expenses.~~clause and renewable related expenditures.

Depreciation and Amortization increased ~~$32~~$63 million due primarily to a $61 million increase in depreciation related to additional plant placed into service and an increase of $5 million in amortization of Regulatory Assets, partially offset by a $4 million increase in capitalized depreciation.

Non-Operating Pension and OPEB Credits (Costs) reflected an increase of$49 millionin creditsdue to the adoption of new accounting guidance effective January 1, 2018 which no longer allows capitalization of any portion of these benefit costs. See Item 1. Note 2. Recent Accounting Standards.

Interest Expense increased $23 million due primarily to an increase of ~~$19~~$17 million ~~in amortization of Regulatory Assets and a $14 million increase in depreciation due to additional plant in service.~~

~~Interest Expense~~ ~~increased $7 million due primarily to an increase of $5 million due~~related to net debt issuances in ~~2016~~May and September 2018 and December 2017 and a $2$6 million increase ~~in other interest.~~related to clauses.

Income Tax Expense ~~increased $12~~decreased $158 million due primarily to the decrease in the federal statutory income tax rate from 35% in 2017 to 21% in 2018, partially offset by uncertain tax positions, plant-related and ~~plant-related~~flow-through 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 million due to a $14 million increase due to the inclusion of Energy Strong in base rates, $8 million in higher Weather Normalization Clause (WNC) revenue, a $7 million increase due to the GSMP and higher GPRC of $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, partially offset by a $24 million increase due to the inclusion of Energy Strong in base rates.

~~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 million due primarily to a $188 million decrease in BGS revenues due to $116 million in lower sales volumes and $72 million of lower prices, $64 million of lower revenues from collections of NGC and a decrease of $14 million due to lower volumes of Non-Utility Generation energy sold.

Table of Contents

~~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~~Power increased $41 million due primarily to the 2016 return to customers of $50 million of overcollections of STC, 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.

~~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.~~

~~Power~~

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				Increase/ (Decrease)					Nine Months Ended					Increase/ (Decrease)
	September 30,				Increase/ (Decrease)					September 30,					Increase/ (Decrease)
	2018		2017		2018 vs. 2017					2018		2017			2018 vs. 2017
	Millions				Millions			%		Millions					Millions			%
Operating Revenues	$	868	$	846	$	22		3		$	3,038	$	3,033		$	5		—
Energy Costs	431		330		101			31		1,550		1,408			142			10
Operation and Maintenance	231		229		2			1		745		717			28			4
Depreciation and Amortization	94		76		18			24		260		1,191			(931		)	(78	)
Income from Equity Method Investments	5		3		2			67		12		11			1			9
Net Gains (Losses) on Trust Investments	44		19		25			N/A		30		62			(32		)	(52	)
Other Income (Deductions)	14		11		3			27		38		34			4			12
Non-Operating Pension and OPEB Credits (Costs)	4		2		2			100		11		6			5			83
Interest Expense	29		12		17			N/A		47		41			6			15
Income Tax Expense (Benefit)	25		98		(73		)	(74	)	127		(80		)	207			N/A

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

Operating Revenues ~~decreased $202~~increased $22 million due primarily to changes in generation and gas supply revenues.

Gas Supply Revenues increased $24 million due primarily to an increase in sales to third parties due primarily to higher average sale prices coupled with an increase in sales volumes.

Generation Revenues decreased ~~$200~~$1 million due primarily to

a decrease of ~~$110~~$84 million due to higher net MTM losses in ~~2017~~2018 as compared to ~~MTM gains in 2016.~~2017. Of this amount, ~~$98~~$136 million was due to changes in forward power prices, ~~and $12~~partially offset by $52 million ~~was~~ due to ~~greater gains~~lower losses on positions reclassified to realized upon settlement this year as compared to last year, and

a net decrease of ~~$83~~$14 million in electricity sold under our BGS contracts due primarily to lower ~~volumes and lower~~ prices, ~~and~~

~~a decrease of $25 million in energy sales in the PJM region due to lower generation volumes and lower average realized prices,~~

~~Table of Contents~~

partially offset by a net increase of ~~$18~~$48 million in energy sales due primarily to higher ~~capacity revenue~~net volumes sold, which includes the commencement of commercial operations of Keys and Sewaren 7, partially offset by lower average realized prices in the PJM region,

an increase of $41 million due to higher volumes of electricity sold under wholesale load contracts ~~at higher average~~primarily in the PJM region, and

a net increase of $8 million in capacity revenues due primarily to increases in cleared capacity and auction prices ~~coupled with new solar projects.~~

~~Gas Supply Revenues~~ ~~decreased $2 million due to lower MTM gains~~ in ~~2017 as compared to 2016.~~the PJM region.

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 Power’s obligation under its BGSS contract with PSE&G. Energy Costs ~~decreased $105~~increased $101 million due to

Generation costs ~~decreased $108~~increased $75 million due primarily to

~~a net decrease~~ higher fuel costs reflecting utilization of ~~$59 million due to charges associated with the early retirement~~higher volumes of ~~the Mercer~~gas 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~~higher natural gas ~~costs reflecting lower~~prices in the PJM region. Higher gas volumes

~~a net decrease~~ were primarily driven by the commencement of ~~$11 million primarily due to lower congestion costs in PJM due to lower congestion rates coupled with less congestion volumes,~~commercial operations of Keys and

~~a decrease of $8 million due to MTM gains in 2017 as compared to MTM losses in 2016.~~ Sewaren 7.

Gas costs increased $3$26 million due mainly to ~~a net~~an increase ~~of $2 million related to~~in sales to third parties ~~of which $5 million was~~ due primarily to higher average gas costs ~~partially offset by $3 million due to lower~~coupled with an increase in volumes sold.

~~Operation and Maintenance~~ ~~decreased $62 million due primarily to~~

~~a $51 million decrease at our fossil plants, due to the retirement of the Hudson and Mercer units on June 1, 2017, and~~

~~a $10 million net decrease related to our nuclear plants due primarily to lower labor-related costs.~~

Depreciation and Amortization ~~decreased~~increased $1018 million due primarily to

~~$19 million 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~~an $11 million increase due to ~~additional nuclear plant~~Keys and Sewaren 7 fossil stations placed into ~~service.~~service, and

Table of Contents

a $6 million increase due primarily to a higher nuclear asset base from increased capitalized asset retirement costs.

~~Other Income (Deductions)~~Net Gains (Losses) on Trust Investments increased ~~$18~~$25 million due primarily to ~~higher~~the inclusion in 2018 of $34 million of net unrealized gains on equity investments in the NDT Fund in accordance with new accounting guidance and a $5 million decrease in other-than-temporary impairments of equity securities in the NDT Fund, offset by a $14 million decrease in net realized gains ~~in the~~on NDT ~~Fund.~~Fund investments.

Interest Expense ~~decreased $12~~increased $17 million due primarily to

~~a $7~~ $11 million ~~decrease due to~~in lower interest capitalized from Keys and Sewaren 7 fossil stations being placed into service, partially offset by higher interest capitalized for the construction of ~~three new fossil stations:~~ BH5 ~~Sewaren 7~~ and ~~Keys, and~~

a $5$7 million ~~decrease~~increase due to a June 2018 debt ~~maturities in September 2016.~~issuance.

Income Tax Expense (Benefit) ~~reflected anincreased tax expense of $8~~decreased $73 million due primarily to ~~changes~~lower pre-tax income resulting in $34 million of the decrease, the remeasurement of the reserve for uncertain tax positions in connection with the nuclear carryback claim and 2011 and 2012 federal tax audit of $28 million and the decrease in the ~~manufacturing deduction and higher pre-tax~~federal statutory income tax rate from 35% in ~~2017.~~2017 to 21% in 2018 of $19 million, partially offset by the New Jersey surtax of $7 million.

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

Operating Revenues~~decreased$16 million~~ increased $5 million due primarily to changes in generation and gas supply revenues.

Gas Supply Revenuesincreased $54 million due primarily to

an increase of $40 million related to sales to third parties due primarily to an increase in sales volumes, and

a net increase of $31 million in sales under the BGSS contract, of which $43 million was due to an increase in sales volumes due to colder average temperatures during the 2018 heating season, partially offset by $12 million due to lower average sales prices,

partially offset by a decrease of $17 million due to net MTM losses in 2018 compared to net gains in 2017.

Generation Revenues decreased ~~$101~~$48 million due primarily to

a ~~net~~ decrease of ~~$115 million in energy sales in the PJM and New England regions due primarily to lower average realized prices,~~

~~a decrease of $91 million in electricity sold under our BGS contracts due to lower volumes and lower prices,~~

~~a net decrease of $11 million in operating reserves in the PJM region, and~~

~~a charge of $10~~$73 million due to ~~an increase~~higher net MTM losses in ~~the FERC reserve accrual related~~2018 as compared to ~~the PJM bidding matter see Item 1. Note 9. Commitments and Contingent Liabilities,~~

~~Table of Contents~~

2017. Of this amount, there was a $214 million decrease due to changes in forward prices, partially offset by ~~an increase of $86~~$141 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,

a decrease of $43 million in electricity sold under our BGS contracts due primarily to lower prices, and

a net decrease of $39 million in energy sales due primarily to lower average realized prices in the PJM region partially offset by higher net volumes in PJM, which includes the commencement of commercial operations of Keys and Sewaren 7, and higher average prices in the New England (NE) and New York (NY) regions,

partially offset by a ~~decrease of $24 million due to changes in forward power prices.~~

a net increase of ~~$31~~$77 million due primarily to higher volumes of electricity sold under wholesale load contracts in the PJM region, partially offset by lower volumes of electricity sold under wholesale load contracts in the NE region, ~~and~~

ana net increase of ~~$10 million due to new solar projects.~~

~~Gas Supply Revenuesincreased~~ ~~$84 million due primarily to~~

~~an increase of $45~~$16 million in ~~sales under the BGSS contract~~capacity revenues due primarily to ~~higher average sales~~increases in cleared capacity and auction 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,~~ in the PJM and NE regions, and

a net increase of ~~$14~~$7 million due to ~~MTM gains in 2017 as compared~~higher sales related to ~~MTM losses in 2016.~~new solar projects.

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 Power’s obligation under its BGSS contract with PSE&G. Energy Costs ~~decreased $20~~increased $142 million due to

Generation costs ~~decreased $76~~increased $72 million due primarily to

a net decrease of $57 million 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,

~~partially offset by~~ higher fuel costs of ~~$12~~$109 million reflecting ~~higher average realized prices for natural gas coupled with the~~ utilization of higher volumes of gas and oil in the PJM region, due primarily to the commencement of commercial operations of Keys and Sewaren 7, coupled with higher prices of natural gas in the PJM and NY regions and higher coal costs in the PJM and NE regions,

partially offset by ~~the utilization of lower volumes of gas and oil,~~

a net ~~increase~~decrease of ~~$10~~$24 million due primarily ~~due~~ to ~~an increase~~a decrease in the volume of energy ~~purchase volumes~~purchased in the NE region to serve load obligations, and

~~an increase~~a decrease of $9$10 million due to MTM gains in 2018 as compared to losses in 2017 ~~as compared~~due to ~~MTM gains~~changes in ~~2016.~~forward prices.

Table of Contents

Gas costs increased ~~$56~~$70 million due mainly to

ana net increase of ~~$32~~$38 million related to sales under the BGSS contract due primarily to ~~higher~~increased volumes sold due to colder average temperatures during the 2018 heating season, partially offset by lower average gas costs, and

ana net increase of ~~$24~~$32 million related to sales to third parties due primarily to an increase in the volume of ~~which $48 million was due to higher average~~ gas ~~costs,~~purchased, partially offset by ~~a $24 million decrease in volumes sold.~~lower average gas costs.

Operation and Maintenance ~~decreased $96~~increased $28 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~~increase related to our nuclear plants, due primarily to ~~lower labor-related costs and~~planned outage costs ~~and~~

~~an $8 million legal accrual~~at our 100%-owned Hope Creek nuclear plant in 2018 as compared to planned outage costs incurred in 2017 for ~~environmental expenses recorded in 2016,~~

~~partially offset by $3 million of costs related to new solar plants placed into service since September 2016.~~our 57%-owned Salem Unit 2.

Depreciation and Amortization ~~increased~~decreased $~~946~~931 million due primarily to

$~~914~~964 million of higher depreciation in 2017 for Hudson and Mercer due to the early retirement of ~~the Hudson and Mercer~~those units,

~~$11~~partially offset by a $15 million ofincrease in 2018 due primarily to a higher nuclear asset base from increased ~~depreciation due to the accelerated~~capitalized asset retirement ~~date at BH3,~~

~~$9 million of higher depreciation due to new solar projects,~~costs, and

a $9$14 million increase due to ~~additional nuclear plant~~Keys and Sewaren 7 fossil stations placed into service.

~~Other Income (Deductions)~~Net Gains (Losses) on Trust Investments ~~increased $64~~decreased $32 million due primarily to ~~$57~~a $22 million decrease in net realized gains on NDT Fund investments and the inclusion in 2018 of $16 million of ~~higher~~ net ~~realized gains~~unrealized losses on equity investments in the NDT Fund ~~and $3~~in accordance with new accounting guidance, partially offset by a $9 million ~~of higher net realized gains~~decrease in ~~the Rabbi Trust Fund.~~

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~~Other-Than-Temporary Impairments~~ ~~decreased $16 million due to lower~~other-than-temporary impairments of equity securities in the NDT ~~Fund in 2017.~~Fund.

Interest Expense ~~decreased $25~~increased $6 million due primarily to

a ~~$16~~$9 million ~~decrease~~increase due to ~~higher interest capitalized for the construction of three new fossil stations: BH5, Sewaren 7 and Keys, and~~

a ~~net $7 million decrease due to~~June 2018 debt ~~maturities in September 2016,~~issuance, partially offset by a ~~debt issuance~~decrease of $2 million in ~~June 2016.~~capitalized interest.

Income Tax Expense (Benefit) ~~decreased $288~~increased $207 million ~~in 2017~~ due primarily to pre-tax income in 2018 as compared to a pre-tax loss in 2017. This increase in income tax expense was diminished by the decrease in the federal statutory income tax rate from 35% in 2017 ~~as compared~~ to ~~pre-tax income~~21% in ~~2016.~~2018 and the remeasurement of the reserve for uncertain tax positions in connection with the nuclear carryback claim and the 2011 and 2012 federal tax audit.

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~~2018, our operating cash flow decreased $27241 million as compared to the same period in ~~2016.~~2017. The net change was due primarily to the net ~~changes~~change from ~~PSE&G and~~ Power as discussed ~~below as well as net tax payments at PSEG and its other subsidiaries.~~below.

PSE&G

PSE&G’s operating cash flow ~~decreased~~increased $85 million from $~~1,401~~1,392 million to $~~1,393~~1,397 million for the nine months ended September 30, ~~2017~~2018, as compared to the same period in ~~2016~~2017, due primarily to ~~lower tax refunds and a decrease~~an increase of ~~$49~~$86 million due to a change in regulatory deferrals, ~~partially~~higher earnings, and an increase of $48 million due primarily to a reduction in unbilled revenues resulting from lower prices and volumes in 2018, offset by ~~higher earnings.~~a tax refund in 2017.

Power

Power’s operating cash flow decreased $11244 million from $~~1,260~~1,249 million to $~~1,249~~1,005 million for the nine months ended September 30, ~~2017~~2018, as compared to the same period in ~~2016,~~2017, due ~~primarily~~ to ~~tax payments in 2017 as compared to tax refunds in 2016 and lower earnings, partially offset by a $68 million decrease~~an increase in margin deposit requirements of $141 million, and higher generation costs, offset by lower tax payments in 2018 compared to 2017, a ~~$30~~$23 million increase from net ~~collection~~collections of counterparty ~~receivables.~~receivables, and a decrease of $10 million in payments to counterparties.

Short-Term Liquidity

PSEG meets its short-term liquidity requirements, as well as those of 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.

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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~~2018 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, 2018
Company/Facility	Total Facility		Usage		Available Liquidity
	Millions
PSEG	$	1,500	$	393	$	1,107
PSE&G	600		56		544
Power	2,200		213		1,987
Total	$	4,300	$	662	$	3,638

As of September 30, ~~2017,~~2018, 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 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 Power’s

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credit rating certain of 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 Power were to lose its investment grade credit rating was approximately ~~$899~~$888 million and ~~$783~~$848 million as of September 30, ~~2017~~2018 and December 31, ~~2016,~~2017, respectively.

For additional information, see Item 1. Note ~~10.~~11. Debt and Credit Facilities.

Long-Term Debt Financing

During the next twelve months, PSEG has a $700 million floating rate ~~$500 million~~ term loan maturing in ~~November 2017.~~June 2019, PSE&G has ~~$400~~$250 million of ~~5.30%~~1.80% Medium-Term Notes maturing in ~~May 2018~~June 2019 and ~~$350~~$250 million of ~~2.30%~~2.00% Medium-Term Notes maturing in ~~September~~August 2019 and Power has $250 million of 2.45% Senior Notes maturing in November 2018.

For ~~a discussion of our long-term debt issuances and maturities during 2017,~~additional information see Item 1. Note ~~10.~~11. Debt and Credit Facilities.

Common Stock Dividends

On July ~~18, 2017,~~17, 2018, our Board of Directors approved a ~~$0.43~~$0.45 dividend per share of common stock for the third quarter of ~~2017. This reflects~~2018. These declarations reflect an indicative annual dividend rate of ~~$1.72~~$1.80 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.~~Note17. 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 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~~

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




	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
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.

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CAPITAL REQUIREMENTS

We expect that all of our capital requirements over the next three years will come from a combination of internally generated funds and external debt financing. There were no material changes to our projected capital expenditures as compared to amounts disclosed in our ~~2016~~2017 Form ~~10-K.~~10-K other than the inclusion of GSMP II, which was approved in May 2018. See Executive Overview of 2018 and Future Outlook for additional information.

PSE&G

During the nine months ended September 30, ~~2017,~~2018, PSE&G made capital expenditures of ~~$2,118~~$2,228 million, primarily for T&D system reliability. This does not include expenditures for cost of removal, net of salvage, of ~~$72~~$121 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.

Power

During the nine months ended September 30, ~~2017,~~2018, Power made capital expenditures of ~~$779~~$679 million, excluding $~~124~~121 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.

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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. 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,~~2018, MTM VaR ~~remained~~was relatively stable between a low of $5$6 million and a high of $9$11 million at the 95% confidence level. The range of VaR was narrower for the three months ended September 30, ~~2017~~2018 as compared with the year ended December 31, ~~2016.~~2017.

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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, 2018		Year Ended December 31, 2017
	Millions
95% Confidence Level, Loss could exceed VaR one day in 20 days
Period End	$	10	$	39
Average for the Period	$	7	$	10
High	$	11	$	39
Low	$	6	$	5
99.5% Confidence Level, Loss could exceed VaR one day in 200 days
Period End	$	16	$	60
Average for the Period	$	11	$	15
High	$	17	$	60
Low	$	9	$	8

See Item 1. Note ~~11.~~12. Financial Risk Management Activities for a discussion of credit risk.

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ITEM 4.	CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

PSEG, PSE&G and 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 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 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 Power

There have been no changes in internal control over financial reporting that occurred during the third quarter of ~~2017~~2018 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~~2017 Annual Report on Form 10-K, see Part I, Item 1. Note 9.10. Commitments and Contingent Liabilities and Item 5. Other Information.


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~~2017 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 as of September 30, ~~2017.~~

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~~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.2018.


ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

~~The following table indicates our~~In December 2017, we entered into a share repurchase plan that complies with Rule 10b5-1 of the Securities Exchange Act of 1934, as amended, solely with respect to the repurchase of shares to satisfy obligations under equity compensation awards that are expected to vest or be exercised in 2018 and under PSEG’s Employee Stock Purchase Plan for expected employee purchases in 2018. There were no common share repurchases in the open market ~~to satisfy obligations under various equity compensation awards~~ during the third quarter of ~~2017~~2018.

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 —
$ —

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ITEM 5. OTHER INFORMATION

Certain information reported in the ~~2016~~2017 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~~2017 Annual Report on Form 10-K and the Quarterly ~~Report~~Reports on Form 10-Q for the quarters ended March 31, ~~2017~~2018 and June 30, ~~2017.~~2018. References are to the related pages on the ~~Forms~~Form 10-K and 10-Q as printed and distributed.

~~Employee Relations~~

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Federal Regulation

Capacity Market Issues—PJM

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 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.~~

~~Federal Regulation~~

~~FERC~~

~~Energy Clearing Prices/Price Formation Initiatives~~

~~December 31, 2016~~ Form 10-K page 16, ~~and~~ March 31, ~~2017~~2018 Form 10-Q on page ~~76.~~80 and June 30, 2018 Form 10-Q on page 88. ~~Energy clearing prices in the markets~~In June 2018, FERC issued an order finding that PJM’s current capacity market is unjust and unreasonable and established a new proceeding to address an alternative approach in which ~~we operate are~~PJM would: (1) modify PJM’s Minimum Offer Price Rule so that it would apply to new and existing resources that receive out-of-market payments, regardless of resource type; and (2) establish an option that would allow, on a resource-specific basis, resources receiving out-of-market support to be removed from the PJM capacity market, along with a commensurate amount of load, for some period of time. In response, PJM proposed a two-settlement auction mechanism in which the first stage would set the resource commitment and the second stage would establish the clearing price. During the second stage, the resources receiving out-of-market support would be removed from the auction before the price is established. We generally ~~based on bids submitted by generating units. Under FERC-approved~~support PJM’s proposal, but have some concerns about aspects of it that could reduce payments to nuclear units that receive out-of-market support payments. FERC’s potential action in this proceeding could cause nuclear units that receive ZEC payments to lose capacity market ~~rules, bids are subject~~revenues if states do not take steps to ~~price caps and mitigation rules applicable to certain generation units. FERC rules also govern~~address the ~~overall design~~potential loss of ~~these markets. At present, all units within a delivery zone receive a clearing price based~~capacity revenues. In addition, depending on the ~~bid~~outcome of ~~the marginal unit (i.e. the last unit that must~~this matter, our fossil generating stations could be dispatched to serve the needs of load) which can vary by location. In addition, recent rule changes in the energy markets administered by PJM and ISO-NE (see Capacity Market Issues below) impose rigorous performance obligations and nonperformance penalties on resources during times of system stress. These FERC rules provide an opportunity for bonus payments or require the payment of penalties depending on whether a unit is available during a performance hour.

FERC has also 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.impacted. 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,~~ Transmission Regulation-Transmission Policy Developments

March 31, ~~2017~~2018 Form 10-Q on page 7680. In February 2018, FERC issued an order finding that the transmission planning procedures used by the PJM transmission owners, a group that includes PSE&G, for supplemental projects do not adhere to the coordination and ~~June 30, 2017 Form 10-Q on page 83.~~ transparency principles of FERC’s Order No. 890. FERC determined that certain terms and conditions in the PJM ~~the New York Independent System Operator (NYISO)~~governing documents are unjust and unreasonable. FERC directed PJM and the ~~Independent System Operator New England, Inc. each have capacity markets that have been~~PJM transmission owners to submit certain revisions to the manner in which the stakeholder process for supplemental projects is conducted. PSE&G participated in the PJM transmission owners’ compliance filing, which was approved by FERC. FERC regulates these markets and continues to examine whether the market design for each of these three capacity markets is working optimally. Various forums are considering how the competitive market framework can incorporate or be reconciled with state public policies that support particular resources 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.

~~Capacity Market Issues—PJM~~

~~December 31, 2016 Form 10-K page 16, March 31, 2017 Form 10-Q on page 76 and June 30, 2017 Form 10-Q page 83.~~ PJM issued a series of white papers in response to public policies that seek to recognize value associated 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

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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~~Return on ~~page 77 and June 30, 2017 Form 10-Q on page 83.~~Equity (ROE)

In ~~a February 2016 order,~~October 2018, 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. Court of Appeals for the D.C. Circuit (D.C. Circuit) and PSE&G has intervened in support 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 establishing a new framework for determining whether a company’s ROE is unjust and unreasonable. The order was issued in a proceeding that was remanded to FERC from D.C. Circuit concerning the ~~regulated electric, natural gas~~establishment of the New England Transmission Owners’ ROE. FERC’s order proposes a new method for evaluating whether an existing ROE remains just and ~~water/wastewater utilities~~reasonable. Under FERC’s approach, FERC will determine a composite zone of reasonableness based on the results of three financial models, and if the targeted utility’s existing ROE falls within the range of just and reasonable ROEs for its risk profile, FERC will dismiss the complaint. However, if FERC determines that an existing ROE is unjust and unreasonable, it proposes to ~~further reduce~~rely on four financial models: a discounted cash flow, a risk premium analysis, a capital-asset pricing model analysis and an expected earnings analysis. We are still analyzing the potential ~~for cyber threats to~~impact of these methodologies and cannot predict the ~~reliability and resiliency~~outcome 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.

~~Table of Contents~~

~~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.proceeding.

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. Circuit challenging the EPA’s Supplemental Finding. The D.C. Circuit is holding the case in abeyance pending further directions from the EPA. We do not expect this Supplemental Finding to impact operation of our facilities.

Climate ~~Change~~

COChange—C0₂Regulation under the Clean Air Act ~~(CAA)~~

December 31, ~~2016~~2017 Form 10-K on page ~~23.~~22. In ~~March 2017, the President of the United States issued an Executive Order that instructed~~August 2018, the EPA ~~to review~~released the ~~New Source Performance Standards that establish emissions standards~~proposed Affordable Clean Energy (ACE) rule as a replacement for CO₂ ~~for certain new fossil power plants and~~ the EPA’s 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, theThe EPA Administrator signed a proposed repeal of the ~~CPP. The EPA Administrator concluded~~CPP which had established state-specific greenhouse gas emissions targets on the basis that the CPP ~~exceeds~~exceeded the EPA’s statutory authority by considering measures that ~~are~~were beyond the control of the owners of ~~the affected sources (fossil~~existing fossil fuel-fired electric generating ~~units). Whether~~units. The proposed ACE rule gives states great flexibility to evaluate specific heat rate improvement technologies and practices to be applied at coal-fired electric generating units. States have three years from the ~~EPA chooses~~date of finalization to ~~propose~~submit a ~~replacement rule has not been decided. PSEG~~plan that establishes a standard of performance that reflects the degree of emission limitation through the application of heat rate improvement technologies and practices. We 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 of 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.

Table of Contents


ITEM 6.	EXHIBITS

A listing of exhibits being filed with this document is as follows:



a. PSEG:
~~Exhibit 10~~		~~Key Executive Severance Plan of Public Service Enterprise Group Incorporated, Amended effective July 18, 2017~~
Exhibit 12:		Computation of Ratios of Earnings to Fixed Charges Plus Preferred Securities Dividend Requirements
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:		XBRL Instance Document
Exhibit 101.SCH:		XBRL Taxonomy Extension Schema
Exhibit 101.CAL:		XBRL Taxonomy Extension Calculation Linkbase
Exhibit 101.LAB:		XBRL Taxonomy Extension Labels Linkbase
Exhibit 101.PRE:		XBRL Taxonomy Extension Presentation Linkbase
Exhibit 101.DEF:		XBRL Taxonomy Extension Definition Document

b. PSE&G:
~~Exhibit 10~~		~~Key Executive Severance Plan of Public Service Enterprise Group Incorporated, Amended effective July 18, 2017~~
Exhibit 12.1:		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:		XBRL Instance Document
Exhibit 101.SCH:		XBRL Taxonomy Extension Schema
Exhibit 101.CAL:		XBRL Taxonomy Extension Calculation Linkbase
Exhibit 101.LAB:		XBRL Taxonomy Extension Labels Linkbase
Exhibit 101.PRE:		XBRL Taxonomy Extension Presentation Linkbase
Exhibit 101.DEF:		XBRL Taxonomy Extension Definition Document

c. Power:
~~Exhibit 10~~		~~Key Executive Severance Plan of Public Service Enterprise Group Incorporated, Amended effective July 18, 2017~~
Exhibit 12.2:		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:		XBRL Instance Document
Exhibit 101.SCH:		XBRL Taxonomy Extension Schema
Exhibit 101.CAL:		XBRL Taxonomy Extension Calculation Linkbase
Exhibit 101.LAB:		XBRL Taxonomy Extension Labels Linkbase
Exhibit 101.PRE:		XBRL Taxonomy Extension Presentation Linkbase
Exhibit 101.DEF:		XBRL Taxonomy Extension Definition Document

Table of 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/ STUART J. BLACK
	Stuart J. Black Vice President and Controller (Principal Accounting Officer)

Date: October ~~31, 2017~~30, 2018

~~Table of 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 ELECTRIC AND GAS COMPANY
(Registrant)

By:	/S/ STUART J. BLACK
	Stuart J. Black Vice President and Controller (Principal Accounting Officer)

Date: October ~~31, 2017~~30, 2018

~~Table of 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.



PSEG POWER LLC
(Registrant)

By:	/S/ STUART J. BLACK
	Stuart J. Black Vice President and Controller (Principal Accounting Officer)

Date: October ~~31, 2017~~30, 2018

9291



Commission File Number	Registrants, State of Incorporation, Address, and Telephone Number	I.R.S. Employer Identification No.
001-09120	PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED (A New Jersey Corporation) 80 Park Plaza Newark, New Jersey 07102 973 430-7000 ~~http://www.pseg.com~~	22-2625848
001-00973	PUBLIC SERVICE ELECTRIC AND GAS COMPANY (A New Jersey Corporation) 80 Park Plaza Newark, New Jersey 07102 973 430-7000 ~~http://www.pseg.com~~	22-1212800
001-34232	PSEG POWER LLC (A Delaware Limited Liability Company) 80 Park Plaza Newark, New Jersey 07102 973 430-7000 ~~http://www.pseg.com~~	22-3663480



Public Service Enterprise Group Incorporated	Large accelerated filer x	Accelerated filer o	Non-accelerated filer o	Smaller reporting company o	Emerging growth company o

Public Service Electric and Gas Company	Large accelerated filer o	Accelerated filer o	Non-accelerated filer x	Smaller reporting company o	Emerging growth company o

PSEG Power LLC	Large accelerated filer o	Accelerated filer o	Non-accelerated filer x	Smaller reporting company o	Emerging growth company o



		Page
FORWARD-LOOKING STATEMENTS		ii
FILING FORMAT		iii
PART I. FINANCIAL INFORMATION
Item 1.	Financial Statements
	Public Service Enterprise Group Incorporated	1
	Public Service Electric and Gas Company	6
	PSEG Power LLC	11
	Notes to Condensed Consolidated Financial Statements
	Note 1. Organization ~~and~~, Basis of Presentation	16
	~~Note 2. Recent~~ and Significant Accounting ~~Standards~~Policies	16
	Note ~~3. Early Plant Retirements~~2. Recent Accounting Standards	1917
	Note 3. Revenues	20
	Note 4. ~~Variable Interest Entity (VIE)~~	21
	~~Note 5. Rate Filings~~	21
	~~Note 6. Financing Receivables~~	22
	~~Note 7. Available-for-Sale Securities~~Early Plant Retirements	25
	Note 5. Variable Interest Entity (VIE)	27
	Note 6. Rate Filings	27
	Note 7. Financing Receivables	28
	Note 8. Trust Investments	31
	Note 9. Pension and Other Postretirement Benefits (OPEB)	30
	~~Note 9. Commitments and Contingent Liabilities~~	3236
	Note 10. ~~Debt~~Commitments and ~~Credit Facilities~~Contingent Liabilities	4038
	Note 11. ~~Financial Risk Management Activities~~Debt and Credit Facilities	4144
	Note 12. ~~Fair Value Measurements~~Financial Risk Management Activities	46
	Note 13. ~~Other Income and Deductions~~Fair Value Measurements	5450
	Note 14. Other Income ~~Taxes~~(Deductions)	5558
	Note 15. Income Taxes	59
	Note 16. Accumulated Other Comprehensive Income (Loss), Net of Tax	5661
	Note ~~16.~~17. Earnings Per Share (EPS) and Dividends	60
	~~Note 17. Financial Information by Business Segments~~	6165
	Note 18. ~~Related-Party Transactions~~Financial Information by Business Segment	6266
	Note 19. Related-Party Transactions	66
	Note 20. Guarantees of Debt	6468
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	6771
	Executive Overview of ~~2017~~2018 and Future Outlook	6771
	Results of Operations	7579
	Liquidity and Capital Resources	8084
	Capital Requirements	8286
	Accounting Matters	8286
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	8287
Item 4.	Controls and Procedures	8388

PART II. OTHER INFORMATION
Item 1.	Legal Proceedings	8388
Item 1A.	Risk Factors	8388
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	8488
Item 5.	Other Information	8588
Item 6.	Exhibits	8990
	Signatures	9091




	September 30, 2017			December 31, 2016
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents	$	278		$	423
Accounts Receivable, net of allowances of $59 in 2017 and $68 in 2016	1,022			1,161
Tax Receivable	127			78
Unbilled Revenues	176			260
Fuel	348			326
Materials and Supplies, net	588			561
Prepayments	200			76
Derivative Contracts	84			163
Regulatory Assets	239			199
Other	19			7
Total Current Assets	3,081			3,254
PROPERTY, PLANT AND EQUIPMENT	39,916			39,337
Less: Accumulated Depreciation and Amortization	(9,383		)	(10,051		)
Net Property, Plant and Equipment	30,533			29,286
NONCURRENT ASSETS
Regulatory Assets	3,336			3,319
Long-Term Investments	936			1,050
Nuclear Decommissioning Trust (NDT) Fund	2,012			1,859
Long-Term Tax Receivable	—			104
Long-Term Receivable of Variable Interest Entity (VIE)	599			589
Other Special Funds	229			217
Goodwill	16			16
Other Intangibles	88			98
Derivative Contracts	62			24
Other	265			254
Total Noncurrent Assets	7,543			7,530
TOTAL ASSETS	$	41,157		$	40,070




	September 30, 2018			December 31, 2017
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents	$	88		$	313
Accounts Receivable, net of allowances of $56 in 2018 and $59 in 2017	1,240			1,348
Tax Receivable	225			127
Unbilled Revenues	155			296
Fuel	329			289
Materials and Supplies, net	590			577
Prepayments	214			118
Derivative Contracts	11			29
Regulatory Assets	317			211
Other	46			4
Total Current Assets	3,215			3,312
PROPERTY, PLANT AND EQUIPMENT	43,613			41,231
Less: Accumulated Depreciation and Amortization	(9,832		)	(9,434		)
Net Property, Plant and Equipment	33,781			31,797
NONCURRENT ASSETS
Regulatory Assets	3,761			3,222
Long-Term Investments	923			932
Nuclear Decommissioning Trust (NDT) Fund	2,096			2,133
Long-Term Receivable of Variable Interest Entity (VIE)	682			686
Rabbi Trust Fund	225			231
Goodwill	16			16
Other Intangibles	107			114
Derivative Contracts	2			7
Other	265			266
Total Noncurrent Assets	8,077			7,607
TOTAL ASSETS	$	45,073		$	42,716




	September 30, 2017			December 31, 2016
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES
Long-Term Debt Due Within One Year	$	1,250		$	500
Commercial Paper and Loans	202			388
Accounts Payable	1,305			1,459
Derivative Contracts	7			13
Accrued Interest	136			97
Accrued Taxes	146			31
Clean Energy Program	184			142
Obligation to Return Cash Collateral	132			132
Regulatory Liabilities	44			88
Other	425			426
Total Current Liabilities	3,831			3,276
NONCURRENT LIABILITIES
Deferred Income Taxes and Investment Tax Credits (ITC)	8,931			8,658
Regulatory Liabilities	89			118
Asset Retirement Obligations	748			726
OPEB Costs	1,301			1,324
OPEB Costs of Servco	474			452
Accrued Pension Costs	504			568
Accrued Pension Costs of Servco	113			128
Environmental Costs	399			401
Derivative Contracts	1			3
Long-Term Accrued Taxes	173			180
Other	195			211
Total Noncurrent Liabilities	12,928			12,769
COMMITMENTS AND CONTINGENT LIABILITIES (See Note 9)
CAPITALIZATION
LONG-TERM DEBT	11,274			10,895
STOCKHOLDERS’ EQUITY
Common Stock, no par, authorized 1,000 shares; issued, 2017 and 2016—534 shares	4,938			4,936
Treasury Stock, at cost, 2017 and 2016—29 shares	(750		)	(717		)
Retained Earnings	9,140			9,174
Accumulated Other Comprehensive Loss	(204		)	(263		)
Total Stockholders’ Equity	13,124			13,130
Total Capitalization	24,398			24,025
TOTAL LIABILITIES AND CAPITALIZATION	$	41,157		$	40,070




	September 30, 2017			December 31, 2016
LIABILITIES AND MEMBER’S EQUITY
CURRENT LIABILITIES
Accounts Payable	$	499		$	539
Accounts Payable—Affiliated Companies	128			25
Derivative Contracts	7			8
Accrued Interest	43			20
Other	87			88
Total Current Liabilities	764			680
NONCURRENT LIABILITIES
Deferred Income Taxes and ITC	1,962			2,170
Asset Retirement Obligations	530			511
OPEB Costs	258			251
Derivative Contracts	1			3
Accrued Pension Costs	174			191
Long-Term Accrued Taxes	57			77
Other	123			129
Total Noncurrent Liabilities	3,105			3,332
COMMITMENTS AND CONTINGENT LIABILITIES (See Note 9)
LONG-TERM DEBT	2,385			2,382
MEMBER’S EQUITY
Contributed Capital	2,214			2,214
Basis Adjustment	(986		)	(986		)
Retained Earnings	4,301			4,782
Accumulated Other Comprehensive Loss	(152		)	(211		)
Total Member’s Equity	5,377			5,799
TOTAL LIABILITIES AND MEMBER’S EQUITY	$	11,631		$	12,193


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


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


(B)	Includes primarily alternative revenues at PSE&G, derivative contracts at Power, and lease contracts in Other. For the nine months ended September 30, 2018 and 2017, Other includes a $20 million loss and a $77 million loss, respectively, related to Energy Holdings’ investments in leases.




Delivery Year	$ per MW-Day	MW Cleared
June 2018 to May 2019	$205	9,200
June 2019 to May 2020	$116	8,900
June 2020 to May 2021	$170	8,100
June 2021 to May 2022	$178	7,700




	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.~~




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




	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




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)




	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




	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


~~(A)~~	~~The NDT available-for-sale securities table excludes cash of $1 million which is part of the NDT Fund.~~


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




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


(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.




	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




	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~~2018 BGS auction year became effective on June 1, ~~2017~~2018 when the ~~2014~~2015 BGS auction agreements expired.




Fuel Type	Power's Share of Commitments through 2021
	Millions
Nuclear Fuel
Uranium	$	257
Enrichment	$	328
Fabrication	$	178
Natural Gas	$	963
Coal	$	308




	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




	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




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	$	—




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




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




	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




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




	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