Public Service Enterprise (PEG) 10-K 28 Feb 19 2018 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2018	Feb. 15, 2019	Jun. 30, 2018
Entity Information [Line Items]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2018
Document Fiscal Year Focus	2,018
Document Fiscal Period Focus	FY
Trading Symbol	PEG
Entity Registrant Name	PUBLIC SERVICE ENTERPRISE GROUP INC
Entity Central Index Key	788,784
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		504,999,536
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Emerging Growth Company	false
Entity Small Business	false
Entity Shell Company	false
Entity Public Float			$ 27,172,268,280
PSE&G [Member]
Entity Information [Line Items]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2018
Document Fiscal Year Focus	2,018
Document Fiscal Period Focus	FY
Entity Registrant Name	PUBLIC SERVICE ELECTRIC & GAS CO
Entity Central Index Key	81,033
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		132,450,344
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Emerging Growth Company	false
Entity Small Business	false
Entity Shell Company	false
Power [Member]
Entity Information [Line Items]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2018
Document Fiscal Year Focus	2,018
Document Fiscal Period Focus	FY
Entity Registrant Name	PSEG POWER LLC
Entity Central Index Key	1,158,659
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Emerging Growth Company	false
Entity Small Business	false
Entity Shell Company	false

Consolidated Statements Of Oper

Consolidated Statements Of Operations - USD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Operating Revenues	$ 9,696	$ 9,094	$ 8,966
Operating Expenses [Abstract]
Energy Costs	3,225	2,778	2,901
Operation and Maintenance	3,015	2,901	2,991
Depreciation and Amortization	1,158	1,986	1,476
Total Operating Expenses	7,398	7,665	7,368
OPERATING INCOME	2,298	1,429	1,598
Income from Equity Method Investments	15	14	11
Net Gains (Losses) on Trust Investments	(143)	134	(6)
Other Income (Deductions)	85	82	102
Non-Operating Pension and Other Postretirement Plan Credits (Costs)	76	0	(22)
Interest Expense	(476)	(391)	(385)
Income (Loss) before Income Taxes	1,855	1,268	1,298
Income Tax (Expense) Benefit	(417)	306	(411)
Net Income	$ 1,438	$ 1,574	$ 887
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:
BASIC	504	505	505
DILUTED	507	507	508
EARNINGS PER SHARE:
NET INCOME, BASIC	$ 2.85	$ 3.12	$ 1.76
NET INCOME, DILUTED	$ 2.83	$ 3.10	$ 1.75
PSE&G [Member]
Operating Revenues	$ 6,471	$ 6,324	$ 6,303
Operating Expenses [Abstract]
Energy Costs	2,520	2,421	2,644
Operation and Maintenance	1,575	1,458	1,465
Depreciation and Amortization	770	685	565
Total Operating Expenses	4,865	4,564	4,674
OPERATING INCOME	1,606	1,760	1,629
Net Gains (Losses) on Trust Investments	(1)	2	0
Other Income (Deductions)	80	85	79
Non-Operating Pension and Other Postretirement Plan Credits (Costs)	59	(8)	(15)
Interest Expense	(333)	(303)	(289)
Income (Loss) before Income Taxes	1,411	1,536	1,404
Income Tax (Expense) Benefit	(344)	(563)	(515)
Net Income	1,067	973	889
Power [Member]
Operating Revenues	4,146	3,860	3,861
Operating Expenses [Abstract]
Energy Costs	2,197	1,913	1,824
Operation and Maintenance	999	1,046	1,139
Depreciation and Amortization	354	1,268	881
Total Operating Expenses	3,550	4,227	3,844
OPERATING INCOME	596	(367)	17
Income from Equity Method Investments	15	14	11
Net Gains (Losses) on Trust Investments	(140)	125	(6)
Other Income (Deductions)	21	20	23
Non-Operating Pension and Other Postretirement Plan Credits (Costs)	15	8	(4)
Interest Expense	(76)	(50)	(84)
Income (Loss) before Income Taxes	431	(250)	(43)
Income Tax (Expense) Benefit	(66)	729	61
Net Income	$ 365	$ 479	$ 18

Consolidated Statements Of Comp

Consolidated Statements Of Comprehensive Income - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Net Income	$ 1,438	$ 1,574	$ 887
Other Comprehensive Income (Loss), net of tax
Unrealized Gains (Losses) on Available-for-Sale Securities, net of tax (expense) benefit for the years ended	(17)	44	42
Unrealized Gains (Losses) on Cash Flow Hedges, net of tax (expense) benefit for the years ended	(1)	(2)	2
Pension/OPEB adjustment, net of tax (expense) benefit for the years ended	46	(8)	(12)
Other Comprehensive Income (Loss), net of tax	28	34	32
Comprehensive Income	1,466	1,608	919
PSE&G [Member]
Net Income	1,067	973	889
Other Comprehensive Income (Loss), net of tax
Unrealized Gains (Losses) on Available-for-Sale Securities, net of tax (expense) benefit for the years ended	(1)	(1)	0
Other Comprehensive Income (Loss), net of tax	(1)	(1)	0
Comprehensive Income	1,066	972	889
Power [Member]
Net Income	365	479	18
Other Comprehensive Income (Loss), net of tax
Unrealized Gains (Losses) on Available-for-Sale Securities, net of tax (expense) benefit for the years ended	(13)	46	42
Pension/OPEB adjustment, net of tax (expense) benefit for the years ended	41	(7)	(13)
Other Comprehensive Income (Loss), net of tax	28	39	29
Comprehensive Income	$ 393	$ 518	$ 47

Consolidated Statements Of Co_2

Consolidated Statements Of Comprehensive Income (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Available-for-Sale Securities, tax	$ 11	$ (37)	$ (41)
Change in Fair Value of Derivative Instruments, tax	1	1	(1)
Pension/OPEB adjustment, tax	(18)	(4)	8
PSE&G [Member]
Available-for-Sale Securities, tax	1	0	0
Power [Member]
Available-for-Sale Securities, tax	9	(39)	(41)
Pension/OPEB adjustment, tax	$ (16)	$ (3)	$ 9

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Millions		Dec. 31, 2018	Dec. 31, 2017
CURRENT ASSETS
Cash and Cash Equivalents		$ 177	$ 313
Accounts Receivable, net of allowances		1,435	1,348
Tax Receivable		242	127
Unbilled Revenues		240	296
Fuel		331	289
Materials and Supplies, net		571	577
Prepayments		94	118
Derivative Contracts		11	29
Regulatory Assets		389	211
Other		17	4
Total Current Assets		3,507	3,312
PROPERTY, PLANT AND EQUIPMENT		44,201	41,231
Less: Accumulated Depreciation and Amortization		(9,838)	(9,434)
Net Property, Plant and Equipment		34,363	31,797
NONCURRENT ASSETS
Regulatory Assets		3,399	3,222
Long-Term Investments		896	932
Nuclear Decommissioning Trust (NDT) Fund		1,878	2,133
Long-Term Receivable of VIEs		624	686
Rabbi Trust		224	231
Goodwill		16	16
Other Intangibles		143	114
Derivative Contracts		1	7
Other		275	266
Total Noncurrent Assets		7,456	7,607
Total Assets		45,326	42,716
CURRENT LIABILITIES
Long-Term Debt Due Within One Year		1,294	1,000
Commercial Paper and Loans		1,016	542
Accounts Payable		1,451	1,694
Derivative Contracts		11	16
Accrued Interest		110	103
Accrued Taxes		26	48
Clean Energy Program		143	128
Obligation to Return Cash Collateral		136	129
Regulatory Liabilities		311	47
Other		437	461
Total Current Liabilities		4,935	4,168
NONCURRENT LIABILITIES
Deferred Income Taxes and Investment Tax Credits (ITC)		5,713	5,240
Regulatory Liabilities		3,221	2,948
Asset Retirement Obligations		1,063	1,024
Other Postretirement Benefit (OPEB) Costs		704	1,455
OPEB Costs of Servco		501	542
Accrued Pension Costs		791	537
Accrued Pension Costs of Servco		109	129
Environmental Costs		327	357
Derivative Contracts		4	5
Long-Term Accrued Taxes		181	175
Other		232	221
Total Noncurrent Liabilities		12,846	12,633
COMMITMENTS AND CONTINGENT LIABILITIES
LONG-TERM DEBT
Total Long-Term Debt		13,168	12,068
STOCKHOLDER'S EQUITY
Common Stock		4,980	4,961
Treasury Stock, at cost		(808)	(763)
Retained Earnings		10,582	9,878
Accumulated Other Comprehensive Income (Loss)		(377)	(229)
Total Stockholder's Equity		14,377	13,847
Total Capitalization		27,545	25,915
TOTAL LIABILITIES AND CAPITALIZATION		45,326	42,716
PSE&G [Member]
CURRENT ASSETS
Cash and Cash Equivalents		39	242
Accounts Receivable, net of allowances		879	882
Tax Receivable		20	0
Accounts Receivable-Affiliated Companies		123	0
Unbilled Revenues		240	296
Materials and Supplies, net		196	197
Prepayments		10	44
Regulatory Assets		389	211
Other		11	4
Total Current Assets		1,907	1,876
PROPERTY, PLANT AND EQUIPMENT		31,633	29,117
Less: Accumulated Depreciation and Amortization		(6,277)	(6,101)
Net Property, Plant and Equipment		25,356	23,016
NONCURRENT ASSETS
Regulatory Assets		3,399	3,222
Long-Term Investments		270	280
Rabbi Trust		45	46
Other		132	114
Total Noncurrent Assets		3,846	3,662
Total Assets		31,109	28,554
CURRENT LIABILITIES
Long-Term Debt Due Within One Year		500	750
Commercial Paper and Loans		272	0
Accounts Payable		713	728
Accounts Payable-Affiliated Companies		321	340
Accrued Interest		84	78
Clean Energy Program		143	128
Obligation to Return Cash Collateral		136	129
Regulatory Liabilities		311	47
Other		345	311
Total Current Liabilities		2,825	2,511
NONCURRENT LIABILITIES
Deferred Income Taxes and Investment Tax Credits (ITC)		3,830	3,391
Regulatory Liabilities		3,221	2,948
Asset Retirement Obligations		302	212
Other Postretirement Benefit (OPEB) Costs		486	1,103
Accrued Pension Costs		400	226
Environmental Costs		268	283
Long-Term Accrued Taxes		69	91
Other		124	114
Total Noncurrent Liabilities		8,700	8,368
COMMITMENTS AND CONTINGENT LIABILITIES
LONG-TERM DEBT
Total Long-Term Debt		8,684	7,841
STOCKHOLDER'S EQUITY
Common Stock		892	892
Contributed Capital		1,095	1,095
Basis Adjustment		986	986
Retained Earnings		7,928	6,861
Accumulated Other Comprehensive Income (Loss)		(1)	0
Total Stockholder's Equity		10,900	9,834
Total Capitalization		19,584	17,675
TOTAL LIABILITIES AND CAPITALIZATION		31,109	28,554
Power [Member]
CURRENT ASSETS
Cash and Cash Equivalents		22	32
Accounts Receivable, net of allowances		477	380
Accounts Receivable-Affiliated Companies		274	221
Fuel		331	289
Materials and Supplies, net		373	376
Prepayments		14	11
Derivative Contracts		11	29	[1]
Other		5	3
Total Current Assets		1,507	1,341
PROPERTY, PLANT AND EQUIPMENT		12,224	11,755
Less: Accumulated Depreciation and Amortization		(3,382)	(3,159)
Net Property, Plant and Equipment		8,842	8,596
NONCURRENT ASSETS
Long-Term Investments		86	87
Nuclear Decommissioning Trust (NDT) Fund		1,878	2,133
Rabbi Trust		56	57
Goodwill		16	16
Other Intangibles		143	114
Derivative Contracts		1	7	[1]
Other		65	67
Total Noncurrent Assets		2,245	2,481
Total Assets		12,594	12,418
CURRENT LIABILITIES
Long-Term Debt Due Within One Year		44	250
Accounts Payable		498	712
Derivative Contracts		11	16	[1]
Accounts Payable-Affiliated Companies		16	57
Short Term Loan from Affiliate	[2]	193	281
Accrued Interest		21	20
Other		59	99
Total Current Liabilities		842	1,435
NONCURRENT LIABILITIES
Deferred Income Taxes and Investment Tax Credits (ITC)		1,619	1,406
Asset Retirement Obligations		758	810
Other Postretirement Benefit (OPEB) Costs		176	283
Accrued Pension Costs		246	184
Derivative Contracts		4	5	[1]
Long-Term Accrued Taxes		76	52
Other		122	140
Total Noncurrent Liabilities		3,001	2,880
COMMITMENTS AND CONTINGENT LIABILITIES
LONG-TERM DEBT
Total Long-Term Debt		2,791	2,136
STOCKHOLDER'S EQUITY
Contributed Capital		2,214	2,214
Basis Adjustment		(986)	(986)
Retained Earnings		5,051	4,911
Accumulated Other Comprehensive Income (Loss)		(319)	(172)
Total Stockholder's Equity		5,960	5,967
TOTAL LIABILITIES AND CAPITALIZATION		$ 12,594	$ 12,418
[1]	Substantially all of Power's derivative instruments are contracts subject to master netting agreements. Contracts not subject to master netting or similar agreements are immaterial and did not have any collateral posted or received as of December 31, 2018 and 2017. PSE&G does not have any derivative contracts subject to master netting or similar agreements.
[2]	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.

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Accounts Receivable,allowances	$ 63	$ 59
Common Stock, issued	534,000,000	534,000,000
Common Stock, authorized	1,000,000,000	1,000,000,000
Treasury Stock, Shares	30,000,000	29,000,000
PSE&G [Member]
Accounts Receivable,allowances	$ 63	$ 59
Common Stock, issued	132,000,000	132,000,000
Common Stock, authorized	150,000,000	150,000,000

Consolidated Statements Of Cash

Consolidated Statements Of Cash Flows - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$ 1,438	$ 1,574	$ 887
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	1,158	1,986	1,476
Amortization of Nuclear Fuel	187	199	203
Emission Allowances and Renewable Energy Credit Compliance Accrual	97	103	109
Impairment Costs for Early Plant Retirements	0	0	102
Provision for Deferred Income Taxes (Other than Leases) and ITC	568	(167)	474
Non-Cash Employee Benefit Plan Costs	70	89	127
Leveraged Lease Income, Adjusted for Rents Received and Deferred Taxes	(149)	(159)	(6)
Gain on Sale of Hudson and Mercer	(54)	0	0
Net (Gain) Loss on Lease Investments	5	48	92
Net Realized and Unrealized (Gains) Losses on Energy Contracts and Other Derivatives	116	188	183
Net Change in Regulatory Assets and Liabilities	(153)	(188)	(138)
Cost of Removal	(160)	(107)	(131)
Net Realized (Gains) Losses and (Income) Expense from NDT Fund	98	(156)	(26)
Net Change in Certain Current Assets and Liabilities:
Margin Deposits	(247)	(90)	(76)
Tax Receivable	17	65	303
Accrued Taxes	(69)	16	3
Other Current Assets and Liabilities	70	(72)	(179)
Employee Benefit Plan Funding and Related Payments	(101)	(81)	(103)
Other	22	12	13
Net Cash Provided By (Used In) Operating Activities	2,913	3,260	3,313
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment	(3,912)	(4,190)	(4,199)
Purchase of Emissions Allowances and RECs	(146)	(117)	(99)
Proceeds from Sale of Available-for-Sale Securities	1,501	2,319	824
Investments in Available-for-Sale Securities	(1,473)	(2,340)	(856)
Other	114	72	82
Net Cash Provided By (Used In) Investing Activities	(3,916)	(4,256)	(4,248)
CASH FLOWS FROM FINANCING ACTIVITIES
Net Change in Commercial Paper and Loans	474	154	24
Issuance of Long-Term Debt	2,750	2,175	2,675
Redemption of Long-Term Debt	(1,350)	(500)	(824)
Cash Dividend Paid	(910)	(870)	(830)
Other	(77)	(74)	(79)
Net Cash Provided By (Used In) Financing Activities	887	885	966
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash	(116)	(111)	31
Cash, Cash Equivalents and Restricted Cash, beginning	315	426	395
Cash, Cash Equivalents and Restricted Cash, ending	199	315	426
Supplemental Disclosure of Cash Flow Information:
Income Taxes Paid (Received)	99	(8)	(245)
Interest Paid, Net of Amounts Capitalized	454	377	365
Accrued Property, Plant and Equipment Expenditures	517	722	664
PSE&G [Member]
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	1,067	973	889
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	770	685	565
Provision for Deferred Income Taxes (Other than Leases) and ITC	405	616	658
Non-Cash Employee Benefit Plan Costs	37	50	72
Net Change in Regulatory Assets and Liabilities	(153)	(188)	(138)
Cost of Removal	(160)	(107)	(131)
Net Change in Certain Current Assets and Liabilities:
Accounts Receivable and Unbilled Revenues	65	(106)	(84)
Fuel, Materials and Supplies	1	(13)	(7)
Prepayments	14	(35)	22
Accounts Payable	64	1	(29)
Accounts Receivable/Payable-Affiliated Companies, net	(139)	101	199
Other Current Assets and Liabilities	5	15	9
Employee Benefit Plan Funding and Related Payments	(85)	(68)	(82)
Other	(38)	(86)	(47)
Net Cash Provided By (Used In) Operating Activities	1,853	1,838	1,896
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment	(2,896)	(2,919)	(2,816)
Proceeds from Sale of Available-for-Sale Securities	20	36	22
Investments in Available-for-Sale Securities	(22)	(37)	(24)
Solar Loan Investments	(5)	7	14
Other	9	10	15
Net Cash Provided By (Used In) Investing Activities	(2,894)	(2,903)	(2,789)
CASH FLOWS FROM FINANCING ACTIVITIES
Net Change in Commercial Paper and Loans	272	0	(153)
Issuance of Long-Term Debt	1,350	775	1,275
Redemption of Long-Term Debt	(750)	0	(271)
Contributed Capital	0	150	250
Other	(14)	(9)	(14)
Net Cash Provided By (Used In) Financing Activities	858	916	1,087
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash	(183)	(149)	194
Cash, Cash Equivalents and Restricted Cash, beginning	244	393	199
Cash, Cash Equivalents and Restricted Cash, ending	61	244	393
Supplemental Disclosure of Cash Flow Information:
Income Taxes Paid (Received)	94	(104)	(295)
Interest Paid, Net of Amounts Capitalized	318	294	273
Accrued Property, Plant and Equipment Expenditures	350	429	420
Power [Member]
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	365	479	18
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	354	1,268	881
Amortization of Nuclear Fuel	187	199	203
Emission Allowances and Renewable Energy Credit Compliance Accrual	97	103	109
Impairment Costs for Early Plant Retirements	0	0	102
Provision for Deferred Income Taxes (Other than Leases) and ITC	206	(807)	(208)
Interest Accretion on Asset Retirement Obligation	41	30	26
Non-Cash Employee Benefit Plan Costs	23	28	39
Gain on Sale of Hudson and Mercer	(54)	0	0
Net Realized and Unrealized (Gains) Losses on Energy Contracts and Other Derivatives	116	188	183
Net Realized (Gains) Losses and (Income) Expense from NDT Fund	98	(156)	(26)
Net Change in Certain Current Assets and Liabilities:
Fuel, Materials and Supplies	(39)	42	31
Margin Deposits	(247)	(90)	(76)
Accounts Receivable	51	(45)	(71)
Accounts Payable	(13)	39	(22)
Accounts Receivable/Payable-Affiliated Companies, net	(56)	(2)	6
Other Current Assets and Liabilities	(40)	10	10
Employee Benefit Plan Funding and Related Payments	(9)	(7)	(13)
Other	4	47	63
Net Cash Provided By (Used In) Operating Activities	1,084	1,326	1,255
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment	(996)	(1,231)	(1,343)
Purchase of Emissions Allowances and RECs	(146)	(117)	(99)
Proceeds from Sale of Available-for-Sale Securities	1,423	2,182	739
Investments in Available-for-Sale Securities	(1,392)	(2,199)	(766)
Increase (Decrease) Due from Affiliates	0	(87)	(276)
Other	60	46	46
Net Cash Provided By (Used In) Investing Activities	(1,051)	(1,232)	(1,147)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of Long-Term Debt	700	0	700
Redemption of Long-Term Debt	(250)	0	(553)
Increase (Decrease) in Due to Affiliates	(88)	281	0
Cash Dividend Paid	(400)	(350)	(250)
Other	(5)	(4)	(6)
Net Cash Provided By (Used In) Financing Activities	(43)	(73)	(109)
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash	(10)	21	(1)
Cash, Cash Equivalents and Restricted Cash, beginning	32	11	12
Cash, Cash Equivalents and Restricted Cash, ending	22	32	11
Supplemental Disclosure of Cash Flow Information:
Income Taxes Paid (Received)	(92)	77	50
Interest Paid, Net of Amounts Capitalized	73	48	81
Accrued Property, Plant and Equipment Expenditures	$ 167	$ 293	$ 244

Consolidated Statements Of Stoc

Consolidated Statements Of Stockholders' Equity - USD ($) shares in Millions, $ in Millions	Total	Common Stock [Member]	Treasury Stock [Member]	Retained Earnings [Member]	Accumulated Other Comprehensive Income (Loss) [Member]	Noncontrolling Interest [Member]	PSE&G [Member]	PSE&G [Member]Common Stock [Member]	PSE&G [Member]Contributed Capital [Member]	PSE&G [Member]Basis Adjustment [Member]	PSE&G [Member]Retained Earnings [Member]	PSE&G [Member]Accumulated Other Comprehensive Income (Loss) [Member]	Power [Member]	Power [Member]Contributed Capital [Member]	Power [Member]Basis Adjustment [Member]	Power [Member]Retained Earnings [Member]	Power [Member]Accumulated Other Comprehensive Income (Loss) [Member]
Beginning Balance (in value) at Dec. 31, 2015	$ 13,067	$ 4,915	$ (671)	$ 9,117	$ (295)	$ 1	$ 7,573	$ 892	$ 695	$ 986	$ 4,999	$ 1	$ 6,002	$ 2,214	$ (986)	$ 5,014	$ (240)
Beginning Balance, shares at Dec. 31, 2015		534	(28)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net Income	887			887			889				889		18			18
Other Comprehensive Income (Loss), net of tax
Other Comprehensive Income (Loss), net of tax	32				32	0	0					0	29				29
Comprehensive Income	919						889						47
Contributed Capital							250		250
Cash Dividends on Common Stock	(830)			(830)	0	0							(250)			(250)
Other	(26)	$ 21	$ (46)	0	0	1
Treasury Stock, Shares, Acquired			(1)
Ending Balance (in value) at Dec. 31, 2016	13,130	$ 4,936	$ (717)	9,174	(263)	0	8,712	892	945	986	5,888	1	5,799	2,214	(986)	4,782	(211)
Ending Balance, shares at Dec. 31, 2016		534	(29)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net Income	1,574			1,574			973				973		479			479
Other Comprehensive Income (Loss), net of tax
Other Comprehensive Income (Loss), net of tax	34				34		(1)					(1)	39				39
Comprehensive Income	1,608						972						518
Contributed Capital							150		150
Cash Dividends on Common Stock	(870)			(870)									(350)			(350)
Other	(21)	$ 25	$ (46)			0
Treasury Stock, Shares, Acquired			0
Ending Balance (in value) at Dec. 31, 2017	13,847	$ 4,961	$ (763)	9,878	(229)	0	9,834	892	1,095	986	6,861	0	5,967	2,214	(986)	4,911	(172)
Ending Balance, shares at Dec. 31, 2017		534	(29)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Cumulative Effect of New Accounting Principle in Period of Adoption	0			176	(176)								0			175	(175)
Net Income	1,438			1,438			1,067				1,067		365			365
Other Comprehensive Income (Loss), net of tax
Other Comprehensive Income (Loss), net of tax	28				28		(1)					(1)	28				28
Comprehensive Income	1,466						1,066						393
Contributed Capital							0
Cash Dividends on Common Stock	(910)			(910)									(400)			(400)
Other	(26)	$ 19	$ (45)			0
Treasury Stock, Shares, Acquired			(1)
Ending Balance (in value) at Dec. 31, 2018	$ 14,377	$ 4,980	$ (808)	$ 10,582	$ (377)	$ 0	$ 10,900	$ 892	$ 1,095	$ 986	$ 7,928	$ (1)	$ 5,960	$ 2,214	$ (986)	$ 5,051	$ (319)
Ending Balance, shares at Dec. 31, 2018		534	(30)

Consolidated Statements Of St_2

Consolidated Statements Of Stockholders' Equity (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Other Comprehensive Income (Loss), tax	$ (6)	$ (40)	$ (34)
Common Stock, Dividends, Per Share, Cash Paid	$ 1.80	$ 1.72	$ 1.64
PSE&G [Member]
Other Comprehensive Income (Loss), tax	$ 1	$ 0	$ 0
Power [Member]
Other Comprehensive Income (Loss), tax	$ (7)	$ (42)	$ (32)

Organization, Basis Of Presenta

Organization, Basis Of Presentation And Summary Of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2018
Organization, Basis Of Presentation And Summary Of Significant Accounting Policies	Organization, Basis of Presentation and Summary of Significant Accounting Policies Public Service Enterprise Group Incorporated (PSEG) is a holding company with a diversified business mix within the energy industry. Its operations are primarily in the Northeastern and Mid-Atlantic United States and in other select markets. PSEG’s principal direct wholly owned subsidiaries are: • Public Service Electric and Gas Company (PSE&G) —which is a public utility engaged principally in the transmission of electricity and distribution of electricity and natural gas in certain areas of New Jersey. PSE&G is subject to regulation by the New Jersey Board of Public Utilities (BPU) and the Federal Energy Regulatory Commission (FERC). PSE&G also invests in regulated solar generation projects and energy efficiency and related programs in New Jersey, which are regulated by the BPU. • PSEG Power LLC (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 are: PSEG Long Island LLC (PSEG LI), which operates the Long Island Power Authority’s (LIPA) electric transmission and distribution (T&D) system under an Operations Services Agreement (OSA); PSEG Energy Holdings L.L.C. (Energy Holdings), which primarily has investments in leveraged leases; and PSEG Services Corporation (Services), which provides certain management, administrative and general services to PSEG and its subsidiaries at cost. Basis of Presentation The respective financial statements included herein have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (SEC) applicable to Annual Reports on Form 10-K and in accordance with accounting guidance generally accepted in the United States (GAAP). Significant Accounting Policies Principles of Consolidation Each company consolidates those entities in which it has a controlling interest or is the primary beneficiary. See Note 5. Variable Interest Entity . Entities over which the companies exhibit significant influence, but do not have a controlling interest and/or are not the primary beneficiary, are accounted for under the equity method of accounting. For investments in which significant influence does not exist and the investor is not the primary beneficiary, the cost method of accounting is applied. All significant intercompany accounts and transactions are eliminated in consolidation. PSE&G and Power also have undivided interests in certain jointly-owned facilities, with each responsible for paying its respective ownership share of construction costs, fuel purchases and operating expenses. PSE&G and Power consolidate their portion of any revenues and expenses related to their respective jointly-owned facilities in the appropriate revenue and expense categories. Accounting for the Effects of Regulation In accordance with accounting guidance for rate-regulated entities, PSE&G’s financial statements reflect the economic effects of regulation. PSE&G defers the recognition of costs (a Regulatory Asset) or records the recognition of obligations (a Regulatory Liability) if it is probable that, through the rate-making process, there will be a corresponding increase or decrease in future rates. Accordingly, PSE&G has deferred certain costs and recoveries, which are being amortized over various future periods. To the extent that collection of any such costs or payment of liabilities becomes no longer probable as a result of changes in regulation and/or competitive position, the associated Regulatory Asset or Liability is charged or credited to income. Management believes that PSE&G’s T&D businesses continue to meet the accounting requirements for rate-regulated entities. For additional information, see Note 7. Regulatory Assets and Liabilities . Cash, Cash Equivalents and Restricted Cash Cash equivalents consist of short-term, highly liquid investments with original maturities of three months or less. Restricted cash consists primarily of deposits received related to various construction projects at PSE&G. The following provides a reconciliation of cash, cash equivalents and restricted cash reported within the Consolidated Balance Sheets that sum to the total of the same such amounts for the beginning ( December 31, 2017 ) and ending periods shown in the Consolidated Statements of Cash Flows for the year ended December 31, 2018 . PSE&G Power Other (A) Consolidated Millions As of December 31, 2017 Cash and Cash Equivalents $ 242 $ 32 $ 39 $ 313 Restricted Cash in Other Current Assets — — — — Restricted Cash in Other Noncurrent Assets 2 — — 2 Cash, Cash Equivalents and Restricted Cash $ 244 $ 32 $ 39 $ 315 As of December 31, 2018 Cash and Cash Equivalents $ 39 $ 22 $ 116 $ 177 Restricted Cash in Other Current Assets 8 — — 8 Restricted Cash in Other Noncurrent Assets 14 — — 14 Cash, Cash Equivalents and Restricted Cash $ 61 $ 22 $ 116 $ 199 (A) Includes amounts applicable to PSEG (parent corporation), Energy Holdings and Services. Derivative Instruments Each company uses derivative instruments to manage risk pursuant to its business plans and prudent practices. Within PSEG and its affiliate companies, Power has the most exposure to commodity price risk. Power is exposed to commodity price risk primarily relating to changes in the market price of electricity, fossil fuels and other commodities. Fluctuations in market prices result from changes in supply and demand, fuel costs, market conditions, weather, state and federal regulatory policies, environmental policies, transmission availability and other factors. Power uses a variety of derivative and non-derivative instruments, such as financial options, futures, swaps, fuel purchases and forward purchases and sales of electricity, to manage the exposure to fluctuations in commodity prices and optimize the value of Power’s expected generation. Changes in the fair market value of the derivative contracts are recorded in earnings. Determining whether a contract qualifies as a derivative requires that management exercise significant judgment, including assessing the contract’s market liquidity. PSEG has determined that contracts to purchase and sell certain products do not meet the definition of a derivative under the current authoritative guidance since they do not provide for net settlement, or the markets are not sufficiently liquid to conclude that physical forward contracts are readily convertible to cash. Under current authoritative guidance, all derivatives are recognized on the balance sheet at their fair value, except for derivatives that are designated as normal purchases and normal sales (NPNS). Further, derivatives that qualify for hedge accounting can be designated as fair value or cash flow hedges. For fair value hedges, changes in fair values for both the derivative and the underlying hedged exposure are recognized in earnings each period. Certain offsetting derivative assets and liabilities are subject to a master netting or similar agreement. In general, the terms of the agreements provide that in the event of an early termination the counterparties have the right to offset amounts owed or owing under that and any other agreement with the same counterparty. Accordingly, these positions are offset on the Consolidated Balance Sheets of Power and PSEG. For cash flow hedges, the portion of the derivative gain or loss that is effective in offsetting the change in the hedged cash flows of the underlying exposure is deferred in Accumulated Other Comprehensive Income (Loss) until earnings are affected by the variability of cash flows of the hedged transaction. Any hedge ineffectiveness is included in current period earnings. For derivative contracts that do not qualify or are not designated as cash flow or fair value hedges or as NPNS, changes in fair value are recorded in current period earnings. PSEG does not currently elect fair value or cash flow hedge accounting on its commodity derivative positions. Contracts that qualify for, and are designated, as NPNS are accounted for upon settlement. Contracts which qualify for NPNS are contracts for which physical delivery is probable, they will not be financially settled, and the quantities under contract are expected to be used or sold in the normal course of business over a reasonable period of time. For additional information regarding derivative financial instruments, see Note 17. Financial Risk Management Activities . Revenue Recognition PSE&G’s regulated electric and gas revenues are recorded primarily based on services rendered to customers. PSE&G records unbilled revenues for the estimated amount customers will be billed for services rendered from the time meters were last read to the end of the respective accounting period. The unbilled revenue is estimated each month based on usage per day, the number of unbilled days in the period, estimated seasonal loads based upon the time of year and the variance of actual degree-days and temperature-humidity-index hours of the unbilled period from expected norms. Regulated revenues from the transmission of electricity are recognized as services are provided based on a FERC-approved annual formula rate mechanism. This mechanism provides for an annual filing of estimated revenue requirement with rates effective January 1 of each year. After completion of the annual period ending December 31, PSE&G files a true-up whereby it compares its actual revenue requirement to the original estimate to determine any over or under collection of revenue. PSE&G records the estimated financial statement impact of the difference between the actual and the filed revenue requirement as a refund or deferral for future recovery when such amounts are probable and can be reasonably estimated in accordance with accounting guidance for rate-regulated entities. The majority of Power’s revenues relate to bilateral contracts, which are accounted for on the accrual basis as the energy is delivered. Power’s revenue also includes changes in the value of energy derivative contracts that are not designated as NPNS. See Note 17. Financial Risk Management Activities for further discussion. PJM Interconnection, L.L.C. (PJM), the Independent System Operator-New England (ISO-NE) and the New York Independent System Operator (NYISO) facilitate the dispatch of energy and energy-related products. Power generally reports electricity sales and purchases conducted with those individual ISOs on a net hourly basis in either Revenues or Energy Costs in its Consolidated Statement of Operations, the classification of which depends on the net hourly activity. Capacity revenue and expense is also reported net based on Power’s monthly net sale or purchase position in the individual ISOs. PSEG LI is the primary beneficiary of Long Island Electric Utility Servco, LLC (Servco). For transactions in which Servco acts as principal, Servco records revenues and the related pass-through expenditures separately in Operating Revenues and Operations and Maintenance (O&M) Expense, respectively. See Note 5. Variable Interest Entity for further information. The majority of Energy Holdings' revenues relate to its investments in leveraged leases. Income on leveraged leases is recognized by a method which produces a constant rate of return on the outstanding net investment in the lease, net of the related deferred tax liability, in the years in which the net investment is positive. Any gains or losses incurred as a result of a lease termination are recorded as revenues as these events occur in the ordinary course of business of managing the investment portfolio. For additional information regarding Revenues, see Note 3. Revenues . Depreciation and Amortization (D&A) PSE&G calculates depreciation under the straight-line method based on estimated average remaining lives of the several classes of depreciable property. These estimates are reviewed on a periodic basis and necessary adjustments are made as approved by the BPU or FERC. The depreciation rate stated as a percentage of original cost of depreciable property was as follows: 2018 2017 2016 Avg Rate Avg Rate Avg Rate Electric Transmission 2.42 % 2.41 % 2.39 % Electric Distribution 2.51 % 2.51 % 2.49 % Gas Distribution 1.61 % 1.63 % 1.63 % Power calculates depreciation on generation-related assets under the straight-line method based on the assets’ estimated useful lives. The estimated useful lives are: • general plant assets— 3 years to 20 years • fossil production assets— 30 years to 67 years • nuclear generation assets—approximately 60 years • pumped storage facilities— 76 years • solar assets— 25 years Allowance for Funds Used During Construction (AFUDC) and Interest Capitalized During Construction (IDC) AFUDC represents the cost of debt and equity funds used to finance the construction of new utility assets at PSE&G. IDC represents the cost of debt used to finance construction at Power. The amount of AFUDC or IDC capitalized as Property, Plant and Equipment is included as a reduction of interest charges or other income for the equity portion. The amounts and average rates used to calculate AFUDC or IDC for the years ended December 31, 2018 , 2017 and 2016 were as follows: AFUDC/IDC Capitalized 2018 2017 2016 Millions Avg Rate Millions Avg Rate Millions Avg Rate PSE&G $ 70 7.74 % $ 73 7.42 % $ 66 7.81 % Power $ 67 4.60 % $ 78 4.60 % $ 54 4.87 % Income Taxes PSEG and its subsidiaries file a consolidated federal income tax return and income taxes are allocated to PSEG’s subsidiaries based on the taxable income or loss of each subsidiary on a separate return basis in accordance with a tax sharing agreement between PSEG and each of its affiliated subsidiaries. Allocations between PSEG and its subsidiaries are recorded through intercompany accounts. Investment tax credits deferred in prior years are being amortized over the useful lives of the related property. Uncertain income tax positions are accounted for using a benefit recognition model with a two-step approach, a more-likely-than-not recognition criterion and a measurement attribute that measures the position as the largest amount of tax benefit that is greater than 50% likely of being realized upon ultimate settlement. If it is not more-likely-than-not that the benefit will be sustained on its technical merits, no benefit will be recorded. Uncertain tax positions that relate only to timing of when an item is included on a tax return are considered to have met the recognition threshold. See Note 21. Income Taxes for further discussion. Impairment of Long-Lived Assets and Leveraged Leases Management evaluates long-lived assets for impairment whenever events or changes in circumstances, such as significant adverse changes in regulation, business climate, counterparty credit worthiness or market conditions, including prolonged periods of adverse commodity and capacity prices or a current expectation that a long-lived asset will be sold or disposed of significantly before the end of its previously estimated useful life, could potentially indicate an asset’s or asset group’s carrying amount may not be recoverable. In such an event, an undiscounted cash flow analysis is performed to determine if an impairment exists. When a long-lived asset’s or asset group’s carrying amount exceeds the associated undiscounted estimated future cash flows, the asset/asset group is considered impaired to the extent that its fair value is less than its carrying amount. An impairment would result in a reduction of the value of the long-lived asset/asset group through a non-cash charge to earnings. See Note 4. Early Plant Retirements for more information. For Power, cash flows for long-lived assets and asset groups are determined at the lowest level for which identifiable cash flows are largely independent of the cash flows of other assets and liabilities. The cash flows from the generation units are generally evaluated at a regional portfolio level (PJM, NYISO, ISO-NE) along with cash flows generated from the customer supply and risk management activities, inclusive of cash flows from contracts, including those that are accounted for as derivatives and meet the NPNS scope exception. In certain cases, generation assets are evaluated on an individual basis where those assets are individually contracted on a long-term basis with a third party and operations are independent of other generation assets (typically Power’s solar plants and Kalaeloa). Energy Holdings’ leveraged leases are comprised of Lease Receivables (net of non-recourse debt), the estimated residual value of leased assets, and unearned and deferred income. Residual values are the estimated values of the leased assets at the end of the respective lease per the original lease terms, net of any subsequent impairments. A review of the residual valuations, which are calculated by discounting the cash flows related to the leased assets after the lease term, is performed at least annually for each plant subject to lease using specific assumptions tailored to each plant. Those valuations are compared to the recorded residual values to determine if an impairment is warranted. Accounts Receivable—Allowance for Doubtful Accounts PSE&G’s accounts receivable are reported in the balance sheet as gross outstanding amounts adjusted for doubtful accounts. The allowance for doubtful accounts reflects PSE&G’s best estimates of losses on the accounts receivable balances. The allowance is based on accounts receivable aging, historical experience, write-off forecasts and other currently available evidence. Accounts receivable are charged off in the period in which the receivable is deemed uncollectible. Recoveries of accounts receivable are recorded when it is known they will be received. Materials and Supplies and Fuel PSE&G’s and Power’s materials and supplies are carried at average cost and charged to inventory when purchased and expensed or capitalized to Property, Plant and Equipment, as appropriate, when installed or used. Fuel inventory at Power is valued at the lower of average cost or market and includes stored natural gas, coal, fuel oil and propane used to generate power and to satisfy obligations under Power’s gas supply contracts with PSE&G. The costs of fuel, including initial transportation costs, are included in inventory when purchased and charged to Energy Costs when used or sold. The cost of nuclear fuel is capitalized within Property, Plant and Equipment and amortized to fuel expense using the units-of-production method. Property, Plant and Equipment PSE&G’s additions to and replacements of existing property, plant and equipment are capitalized at cost. The cost of maintenance, repair and replacement of minor items of property is charged to expense as incurred. At the time units of depreciable property are retired or otherwise disposed of, the original cost, adjusted for net salvage value, is charged to accumulated depreciation. Power capitalizes costs, including those related to its jointly-owned facilities, which increase the capacity, improve or extend the life of an existing asset, represent a newly acquired or constructed asset or represent the replacement of a retired asset. The cost of maintenance, repair and replacement of minor items of property is charged to appropriate expense accounts as incurred. Environmental costs are capitalized if the costs mitigate or prevent future environmental contamination or if the costs improve existing assets’ environmental safety or efficiency. All other environmental expenditures are expensed as incurred. Power also capitalizes spare parts that meet specific criteria. Capitalized spares are depreciated over the remaining lives of their associated assets. Trust Investments These securities comprise the Nuclear Decommissioning Trust (NDT) Fund, a master independent external trust account maintained to provide for the costs of decommissioning upon termination of operations of Power’s nuclear facilities and amounts that are deposited to fund a Rabbi Trust which was established to meet the obligations related to non-qualified pension plans and deferred compensation plans. Effective January 1, 2018, unrealized gains and losses on equity security investments are recorded in Net Income instead of Other Comprehensive Income (Loss). The debt securities continue to be classified as available-for-sale with the unrealized gains and losses recorded as a component of Accumulated Other Comprehensive Income (Loss). Realized gains and losses on both equity and available-for-sale debt security investments are recorded in earnings and are included with the unrealized gains and losses on equity securities in Net Gains (Losses) on Trust Investments. Other-than-temporary impairments on NDT and Rabbi Trust securities are also included in Net Gains (Losses) on Trust Investments. See Note 10. Trust Investments for further discussion. Pension and Other Postretirement Benefits (OPEB) Plans The market-related value of plan assets held for the qualified pension and OPEB plans is equal to the fair value of those assets as of year-end. Fair value is determined using quoted market prices and independent pricing services based upon the security type as reported by the trustee at the measurement date (December 31) for all plan assets. PSEG recognizes a long-term receivable primarily related to future funding by LIPA of Servco’s recognized pension and OPEB liabilities. This receivable is presented separately on the Consolidated Balance Sheet of PSEG as a noncurrent asset. Pursuant to the OSA, Servco records expense for contributions to its pension plan trusts and for OPEB payments made to retirees. See Note 13. Pension, Other Postretirement Benefits (OPEB) and Savings Plan for further discussion. Basis Adjustment PSE&G and Power have recorded a Basis Adjustment in their respective Consolidated Balance Sheets related to the generation assets that were transferred from PSE&G to Power in August 2000 at the price specified by the BPU. Because the transfer was between affiliates, the transaction was recorded at the net book value of the assets and liabilities rather than the transfer price. The difference between the total transfer price and the net book value of the generation-related assets and liabilities, $986 million , net of tax, was recorded as a Basis Adjustment on PSE&G’s and Power’s Consolidated Balance Sheets. The $986 million is an addition to PSE&G’s Common Stockholder’s Equity and a reduction of Power’s Member’s Equity. These amounts are eliminated on PSEG’s consolidated financial statements. Use of Estimates The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
PSE&G [Member]
Organization, Basis Of Presentation And Summary Of Significant Accounting Policies	Organization, Basis of Presentation and Summary of Significant Accounting Policies Public Service Enterprise Group Incorporated (PSEG) is a holding company with a diversified business mix within the energy industry. Its operations are primarily in the Northeastern and Mid-Atlantic United States and in other select markets. PSEG’s principal direct wholly owned subsidiaries are: • Public Service Electric and Gas Company (PSE&G) —which is a public utility engaged principally in the transmission of electricity and distribution of electricity and natural gas in certain areas of New Jersey. PSE&G is subject to regulation by the New Jersey Board of Public Utilities (BPU) and the Federal Energy Regulatory Commission (FERC). PSE&G also invests in regulated solar generation projects and energy efficiency and related programs in New Jersey, which are regulated by the BPU. • PSEG Power LLC (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 are: PSEG Long Island LLC (PSEG LI), which operates the Long Island Power Authority’s (LIPA) electric transmission and distribution (T&D) system under an Operations Services Agreement (OSA); PSEG Energy Holdings L.L.C. (Energy Holdings), which primarily has investments in leveraged leases; and PSEG Services Corporation (Services), which provides certain management, administrative and general services to PSEG and its subsidiaries at cost. Basis of Presentation The respective financial statements included herein have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (SEC) applicable to Annual Reports on Form 10-K and in accordance with accounting guidance generally accepted in the United States (GAAP). Significant Accounting Policies Principles of Consolidation Each company consolidates those entities in which it has a controlling interest or is the primary beneficiary. See Note 5. Variable Interest Entity . Entities over which the companies exhibit significant influence, but do not have a controlling interest and/or are not the primary beneficiary, are accounted for under the equity method of accounting. For investments in which significant influence does not exist and the investor is not the primary beneficiary, the cost method of accounting is applied. All significant intercompany accounts and transactions are eliminated in consolidation. PSE&G and Power also have undivided interests in certain jointly-owned facilities, with each responsible for paying its respective ownership share of construction costs, fuel purchases and operating expenses. PSE&G and Power consolidate their portion of any revenues and expenses related to their respective jointly-owned facilities in the appropriate revenue and expense categories. Accounting for the Effects of Regulation In accordance with accounting guidance for rate-regulated entities, PSE&G’s financial statements reflect the economic effects of regulation. PSE&G defers the recognition of costs (a Regulatory Asset) or records the recognition of obligations (a Regulatory Liability) if it is probable that, through the rate-making process, there will be a corresponding increase or decrease in future rates. Accordingly, PSE&G has deferred certain costs and recoveries, which are being amortized over various future periods. To the extent that collection of any such costs or payment of liabilities becomes no longer probable as a result of changes in regulation and/or competitive position, the associated Regulatory Asset or Liability is charged or credited to income. Management believes that PSE&G’s T&D businesses continue to meet the accounting requirements for rate-regulated entities. For additional information, see Note 7. Regulatory Assets and Liabilities . Cash, Cash Equivalents and Restricted Cash Cash equivalents consist of short-term, highly liquid investments with original maturities of three months or less. Restricted cash consists primarily of deposits received related to various construction projects at PSE&G. The following provides a reconciliation of cash, cash equivalents and restricted cash reported within the Consolidated Balance Sheets that sum to the total of the same such amounts for the beginning ( December 31, 2017 ) and ending periods shown in the Consolidated Statements of Cash Flows for the year ended December 31, 2018 . PSE&G Power Other (A) Consolidated Millions As of December 31, 2017 Cash and Cash Equivalents $ 242 $ 32 $ 39 $ 313 Restricted Cash in Other Current Assets — — — — Restricted Cash in Other Noncurrent Assets 2 — — 2 Cash, Cash Equivalents and Restricted Cash $ 244 $ 32 $ 39 $ 315 As of December 31, 2018 Cash and Cash Equivalents $ 39 $ 22 $ 116 $ 177 Restricted Cash in Other Current Assets 8 — — 8 Restricted Cash in Other Noncurrent Assets 14 — — 14 Cash, Cash Equivalents and Restricted Cash $ 61 $ 22 $ 116 $ 199 (A) Includes amounts applicable to PSEG (parent corporation), Energy Holdings and Services. Derivative Instruments Each company uses derivative instruments to manage risk pursuant to its business plans and prudent practices. Within PSEG and its affiliate companies, Power has the most exposure to commodity price risk. Power is exposed to commodity price risk primarily relating to changes in the market price of electricity, fossil fuels and other commodities. Fluctuations in market prices result from changes in supply and demand, fuel costs, market conditions, weather, state and federal regulatory policies, environmental policies, transmission availability and other factors. Power uses a variety of derivative and non-derivative instruments, such as financial options, futures, swaps, fuel purchases and forward purchases and sales of electricity, to manage the exposure to fluctuations in commodity prices and optimize the value of Power’s expected generation. Changes in the fair market value of the derivative contracts are recorded in earnings. Determining whether a contract qualifies as a derivative requires that management exercise significant judgment, including assessing the contract’s market liquidity. PSEG has determined that contracts to purchase and sell certain products do not meet the definition of a derivative under the current authoritative guidance since they do not provide for net settlement, or the markets are not sufficiently liquid to conclude that physical forward contracts are readily convertible to cash. Under current authoritative guidance, all derivatives are recognized on the balance sheet at their fair value, except for derivatives that are designated as normal purchases and normal sales (NPNS). Further, derivatives that qualify for hedge accounting can be designated as fair value or cash flow hedges. For fair value hedges, changes in fair values for both the derivative and the underlying hedged exposure are recognized in earnings each period. Certain offsetting derivative assets and liabilities are subject to a master netting or similar agreement. In general, the terms of the agreements provide that in the event of an early termination the counterparties have the right to offset amounts owed or owing under that and any other agreement with the same counterparty. Accordingly, these positions are offset on the Consolidated Balance Sheets of Power and PSEG. For cash flow hedges, the portion of the derivative gain or loss that is effective in offsetting the change in the hedged cash flows of the underlying exposure is deferred in Accumulated Other Comprehensive Income (Loss) until earnings are affected by the variability of cash flows of the hedged transaction. Any hedge ineffectiveness is included in current period earnings. For derivative contracts that do not qualify or are not designated as cash flow or fair value hedges or as NPNS, changes in fair value are recorded in current period earnings. PSEG does not currently elect fair value or cash flow hedge accounting on its commodity derivative positions. Contracts that qualify for, and are designated, as NPNS are accounted for upon settlement. Contracts which qualify for NPNS are contracts for which physical delivery is probable, they will not be financially settled, and the quantities under contract are expected to be used or sold in the normal course of business over a reasonable period of time. For additional information regarding derivative financial instruments, see Note 17. Financial Risk Management Activities . Revenue Recognition PSE&G’s regulated electric and gas revenues are recorded primarily based on services rendered to customers. PSE&G records unbilled revenues for the estimated amount customers will be billed for services rendered from the time meters were last read to the end of the respective accounting period. The unbilled revenue is estimated each month based on usage per day, the number of unbilled days in the period, estimated seasonal loads based upon the time of year and the variance of actual degree-days and temperature-humidity-index hours of the unbilled period from expected norms. Regulated revenues from the transmission of electricity are recognized as services are provided based on a FERC-approved annual formula rate mechanism. This mechanism provides for an annual filing of estimated revenue requirement with rates effective January 1 of each year. After completion of the annual period ending December 31, PSE&G files a true-up whereby it compares its actual revenue requirement to the original estimate to determine any over or under collection of revenue. PSE&G records the estimated financial statement impact of the difference between the actual and the filed revenue requirement as a refund or deferral for future recovery when such amounts are probable and can be reasonably estimated in accordance with accounting guidance for rate-regulated entities. The majority of Power’s revenues relate to bilateral contracts, which are accounted for on the accrual basis as the energy is delivered. Power’s revenue also includes changes in the value of energy derivative contracts that are not designated as NPNS. See Note 17. Financial Risk Management Activities for further discussion. PJM Interconnection, L.L.C. (PJM), the Independent System Operator-New England (ISO-NE) and the New York Independent System Operator (NYISO) facilitate the dispatch of energy and energy-related products. Power generally reports electricity sales and purchases conducted with those individual ISOs on a net hourly basis in either Revenues or Energy Costs in its Consolidated Statement of Operations, the classification of which depends on the net hourly activity. Capacity revenue and expense is also reported net based on Power’s monthly net sale or purchase position in the individual ISOs. PSEG LI is the primary beneficiary of Long Island Electric Utility Servco, LLC (Servco). For transactions in which Servco acts as principal, Servco records revenues and the related pass-through expenditures separately in Operating Revenues and Operations and Maintenance (O&M) Expense, respectively. See Note 5. Variable Interest Entity for further information. The majority of Energy Holdings' revenues relate to its investments in leveraged leases. Income on leveraged leases is recognized by a method which produces a constant rate of return on the outstanding net investment in the lease, net of the related deferred tax liability, in the years in which the net investment is positive. Any gains or losses incurred as a result of a lease termination are recorded as revenues as these events occur in the ordinary course of business of managing the investment portfolio. For additional information regarding Revenues, see Note 3. Revenues . Depreciation and Amortization (D&A) PSE&G calculates depreciation under the straight-line method based on estimated average remaining lives of the several classes of depreciable property. These estimates are reviewed on a periodic basis and necessary adjustments are made as approved by the BPU or FERC. The depreciation rate stated as a percentage of original cost of depreciable property was as follows: 2018 2017 2016 Avg Rate Avg Rate Avg Rate Electric Transmission 2.42 % 2.41 % 2.39 % Electric Distribution 2.51 % 2.51 % 2.49 % Gas Distribution 1.61 % 1.63 % 1.63 % Power calculates depreciation on generation-related assets under the straight-line method based on the assets’ estimated useful lives. The estimated useful lives are: • general plant assets— 3 years to 20 years • fossil production assets— 30 years to 67 years • nuclear generation assets—approximately 60 years • pumped storage facilities— 76 years • solar assets— 25 years Allowance for Funds Used During Construction (AFUDC) and Interest Capitalized During Construction (IDC) AFUDC represents the cost of debt and equity funds used to finance the construction of new utility assets at PSE&G. IDC represents the cost of debt used to finance construction at Power. The amount of AFUDC or IDC capitalized as Property, Plant and Equipment is included as a reduction of interest charges or other income for the equity portion. The amounts and average rates used to calculate AFUDC or IDC for the years ended December 31, 2018 , 2017 and 2016 were as follows: AFUDC/IDC Capitalized 2018 2017 2016 Millions Avg Rate Millions Avg Rate Millions Avg Rate PSE&G $ 70 7.74 % $ 73 7.42 % $ 66 7.81 % Power $ 67 4.60 % $ 78 4.60 % $ 54 4.87 % Income Taxes PSEG and its subsidiaries file a consolidated federal income tax return and income taxes are allocated to PSEG’s subsidiaries based on the taxable income or loss of each subsidiary on a separate return basis in accordance with a tax sharing agreement between PSEG and each of its affiliated subsidiaries. Allocations between PSEG and its subsidiaries are recorded through intercompany accounts. Investment tax credits deferred in prior years are being amortized over the useful lives of the related property. Uncertain income tax positions are accounted for using a benefit recognition model with a two-step approach, a more-likely-than-not recognition criterion and a measurement attribute that measures the position as the largest amount of tax benefit that is greater than 50% likely of being realized upon ultimate settlement. If it is not more-likely-than-not that the benefit will be sustained on its technical merits, no benefit will be recorded. Uncertain tax positions that relate only to timing of when an item is included on a tax return are considered to have met the recognition threshold. See Note 21. Income Taxes for further discussion. Impairment of Long-Lived Assets and Leveraged Leases Management evaluates long-lived assets for impairment whenever events or changes in circumstances, such as significant adverse changes in regulation, business climate, counterparty credit worthiness or market conditions, including prolonged periods of adverse commodity and capacity prices or a current expectation that a long-lived asset will be sold or disposed of significantly before the end of its previously estimated useful life, could potentially indicate an asset’s or asset group’s carrying amount may not be recoverable. In such an event, an undiscounted cash flow analysis is performed to determine if an impairment exists. When a long-lived asset’s or asset group’s carrying amount exceeds the associated undiscounted estimated future cash flows, the asset/asset group is considered impaired to the extent that its fair value is less than its carrying amount. An impairment would result in a reduction of the value of the long-lived asset/asset group through a non-cash charge to earnings. See Note 4. Early Plant Retirements for more information. For Power, cash flows for long-lived assets and asset groups are determined at the lowest level for which identifiable cash flows are largely independent of the cash flows of other assets and liabilities. The cash flows from the generation units are generally evaluated at a regional portfolio level (PJM, NYISO, ISO-NE) along with cash flows generated from the customer supply and risk management activities, inclusive of cash flows from contracts, including those that are accounted for as derivatives and meet the NPNS scope exception. In certain cases, generation assets are evaluated on an individual basis where those assets are individually contracted on a long-term basis with a third party and operations are independent of other generation assets (typically Power’s solar plants and Kalaeloa). Energy Holdings’ leveraged leases are comprised of Lease Receivables (net of non-recourse debt), the estimated residual value of leased assets, and unearned and deferred income. Residual values are the estimated values of the leased assets at the end of the respective lease per the original lease terms, net of any subsequent impairments. A review of the residual valuations, which are calculated by discounting the cash flows related to the leased assets after the lease term, is performed at least annually for each plant subject to lease using specific assumptions tailored to each plant. Those valuations are compared to the recorded residual values to determine if an impairment is warranted. Accounts Receivable—Allowance for Doubtful Accounts PSE&G’s accounts receivable are reported in the balance sheet as gross outstanding amounts adjusted for doubtful accounts. The allowance for doubtful accounts reflects PSE&G’s best estimates of losses on the accounts receivable balances. The allowance is based on accounts receivable aging, historical experience, write-off forecasts and other currently available evidence. Accounts receivable are charged off in the period in which the receivable is deemed uncollectible. Recoveries of accounts receivable are recorded when it is known they will be received. Materials and Supplies and Fuel PSE&G’s and Power’s materials and supplies are carried at average cost and charged to inventory when purchased and expensed or capitalized to Property, Plant and Equipment, as appropriate, when installed or used. Fuel inventory at Power is valued at the lower of average cost or market and includes stored natural gas, coal, fuel oil and propane used to generate power and to satisfy obligations under Power’s gas supply contracts with PSE&G. The costs of fuel, including initial transportation costs, are included in inventory when purchased and charged to Energy Costs when used or sold. The cost of nuclear fuel is capitalized within Property, Plant and Equipment and amortized to fuel expense using the units-of-production method. Property, Plant and Equipment PSE&G’s additions to and replacements of existing property, plant and equipment are capitalized at cost. The cost of maintenance, repair and replacement of minor items of property is charged to expense as incurred. At the time units of depreciable property are retired or otherwise disposed of, the original cost, adjusted for net salvage value, is charged to accumulated depreciation. Power capitalizes costs, including those related to its jointly-owned facilities, which increase the capacity, improve or extend the life of an existing asset, represent a newly acquired or constructed asset or represent the replacement of a retired asset. The cost of maintenance, repair and replacement of minor items of property is charged to appropriate expense accounts as incurred. Environmental costs are capitalized if the costs mitigate or prevent future environmental contamination or if the costs improve existing assets’ environmental safety or efficiency. All other environmental expenditures are expensed as incurred. Power also capitalizes spare parts that meet specific criteria. Capitalized spares are depreciated over the remaining lives of their associated assets. Trust Investments These securities comprise the Nuclear Decommissioning Trust (NDT) Fund, a master independent external trust account maintained to provide for the costs of decommissioning upon termination of operations of Power’s nuclear facilities and amounts that are deposited to fund a Rabbi Trust which was established to meet the obligations related to non-qualified pension plans and deferred compensation plans. Effective January 1, 2018, unrealized gains and losses on equity security investments are recorded in Net Income instead of Other Comprehensive Income (Loss). The debt securities continue to be classified as available-for-sale with the unrealized gains and losses recorded as a component of Accumulated Other Comprehensive Income (Loss). Realized gains and losses on both equity and available-for-sale debt security investments are recorded in earnings and are included with the unrealized gains and losses on equity securities in Net Gains (Losses) on Trust Investments. Other-than-temporary impairments on NDT and Rabbi Trust securities are also included in Net Gains (Losses) on Trust Investments. See Note 10. Trust Investments for further discussion. Pension and Other Postretirement Benefits (OPEB) Plans The market-related value of plan assets held for the qualified pension and OPEB plans is equal to the fair value of those assets as of year-end. Fair value is determined using quoted market prices and independent pricing services based upon the security type as reported by the trustee at the measurement date (December 31) for all plan assets. PSEG recognizes a long-term receivable primarily related to future funding by LIPA of Servco’s recognized pension and OPEB liabilities. This receivable is presented separately on the Consolidated Balance Sheet of PSEG as a noncurrent asset. Pursuant to the OSA, Servco records expense for contributions to its pension plan trusts and for OPEB payments made to retirees. See Note 13. Pension, Other Postretirement Benefits (OPEB) and Savings Plan for further discussion. Basis Adjustment PSE&G and Power have recorded a Basis Adjustment in their respective Consolidated Balance Sheets related to the generation assets that were transferred from PSE&G to Power in August 2000 at the price specified by the BPU. Because the transfer was between affiliates, the transaction was recorded at the net book value of the assets and liabilities rather than the transfer price. The difference between the total transfer price and the net book value of the generation-related assets and liabilities, $986 million , net of tax, was recorded as a Basis Adjustment on PSE&G’s and Power’s Consolidated Balance Sheets. The $986 million is an addition to PSE&G’s Common Stockholder’s Equity and a reduction of Power’s Member’s Equity. These amounts are eliminated on PSEG’s consolidated financial statements. Use of Estimates The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Power [Member]
Organization, Basis Of Presentation And Summary Of Significant Accounting Policies	Organization, Basis of Presentation and Summary of Significant Accounting Policies Public Service Enterprise Group Incorporated (PSEG) is a holding company with a diversified business mix within the energy industry. Its operations are primarily in the Northeastern and Mid-Atlantic United States and in other select markets. PSEG’s principal direct wholly owned subsidiaries are: • Public Service Electric and Gas Company (PSE&G) —which is a public utility engaged principally in the transmission of electricity and distribution of electricity and natural gas in certain areas of New Jersey. PSE&G is subject to regulation by the New Jersey Board of Public Utilities (BPU) and the Federal Energy Regulatory Commission (FERC). PSE&G also invests in regulated solar generation projects and energy efficiency and related programs in New Jersey, which are regulated by the BPU. • PSEG Power LLC (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 are: PSEG Long Island LLC (PSEG LI), which operates the Long Island Power Authority’s (LIPA) electric transmission and distribution (T&D) system under an Operations Services Agreement (OSA); PSEG Energy Holdings L.L.C. (Energy Holdings), which primarily has investments in leveraged leases; and PSEG Services Corporation (Services), which provides certain management, administrative and general services to PSEG and its subsidiaries at cost. Basis of Presentation The respective financial statements included herein have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (SEC) applicable to Annual Reports on Form 10-K and in accordance with accounting guidance generally accepted in the United States (GAAP). Significant Accounting Policies Principles of Consolidation Each company consolidates those entities in which it has a controlling interest or is the primary beneficiary. See Note 5. Variable Interest Entity . Entities over which the companies exhibit significant influence, but do not have a controlling interest and/or are not the primary beneficiary, are accounted for under the equity method of accounting. For investments in which significant influence does not exist and the investor is not the primary beneficiary, the cost method of accounting is applied. All significant intercompany accounts and transactions are eliminated in consolidation. PSE&G and Power also have undivided interests in certain jointly-owned facilities, with each responsible for paying its respective ownership share of construction costs, fuel purchases and operating expenses. PSE&G and Power consolidate their portion of any revenues and expenses related to their respective jointly-owned facilities in the appropriate revenue and expense categories. Accounting for the Effects of Regulation In accordance with accounting guidance for rate-regulated entities, PSE&G’s financial statements reflect the economic effects of regulation. PSE&G defers the recognition of costs (a Regulatory Asset) or records the recognition of obligations (a Regulatory Liability) if it is probable that, through the rate-making process, there will be a corresponding increase or decrease in future rates. Accordingly, PSE&G has deferred certain costs and recoveries, which are being amortized over various future periods. To the extent that collection of any such costs or payment of liabilities becomes no longer probable as a result of changes in regulation and/or competitive position, the associated Regulatory Asset or Liability is charged or credited to income. Management believes that PSE&G’s T&D businesses continue to meet the accounting requirements for rate-regulated entities. For additional information, see Note 7. Regulatory Assets and Liabilities . Cash, Cash Equivalents and Restricted Cash Cash equivalents consist of short-term, highly liquid investments with original maturities of three months or less. Restricted cash consists primarily of deposits received related to various construction projects at PSE&G. The following provides a reconciliation of cash, cash equivalents and restricted cash reported within the Consolidated Balance Sheets that sum to the total of the same such amounts for the beginning ( December 31, 2017 ) and ending periods shown in the Consolidated Statements of Cash Flows for the year ended December 31, 2018 . PSE&G Power Other (A) Consolidated Millions As of December 31, 2017 Cash and Cash Equivalents $ 242 $ 32 $ 39 $ 313 Restricted Cash in Other Current Assets — — — — Restricted Cash in Other Noncurrent Assets 2 — — 2 Cash, Cash Equivalents and Restricted Cash $ 244 $ 32 $ 39 $ 315 As of December 31, 2018 Cash and Cash Equivalents $ 39 $ 22 $ 116 $ 177 Restricted Cash in Other Current Assets 8 — — 8 Restricted Cash in Other Noncurrent Assets 14 — — 14 Cash, Cash Equivalents and Restricted Cash $ 61 $ 22 $ 116 $ 199 (A) Includes amounts applicable to PSEG (parent corporation), Energy Holdings and Services. Derivative Instruments Each company uses derivative instruments to manage risk pursuant to its business plans and prudent practices. Within PSEG and its affiliate companies, Power has the most exposure to commodity price risk. Power is exposed to commodity price risk primarily relating to changes in the market price of electricity, fossil fuels and other commodities. Fluctuations in market prices result from changes in supply and demand, fuel costs, market conditions, weather, state and federal regulatory policies, environmental policies, transmission availability and other factors. Power uses a variety of derivative and non-derivative instruments, such as financial options, futures, swaps, fuel purchases and forward purchases and sales of electricity, to manage the exposure to fluctuations in commodity prices and optimize the value of Power’s expected generation. Changes in the fair market value of the derivative contracts are recorded in earnings. Determining whether a contract qualifies as a derivative requires that management exercise significant judgment, including assessing the contract’s market liquidity. PSEG has determined that contracts to purchase and sell certain products do not meet the definition of a derivative under the current authoritative guidance since they do not provide for net settlement, or the markets are not sufficiently liquid to conclude that physical forward contracts are readily convertible to cash. Under current authoritative guidance, all derivatives are recognized on the balance sheet at their fair value, except for derivatives that are designated as normal purchases and normal sales (NPNS). Further, derivatives that qualify for hedge accounting can be designated as fair value or cash flow hedges. For fair value hedges, changes in fair values for both the derivative and the underlying hedged exposure are recognized in earnings each period. Certain offsetting derivative assets and liabilities are subject to a master netting or similar agreement. In general, the terms of the agreements provide that in the event of an early termination the counterparties have the right to offset amounts owed or owing under that and any other agreement with the same counterparty. Accordingly, these positions are offset on the Consolidated Balance Sheets of Power and PSEG. For cash flow hedges, the portion of the derivative gain or loss that is effective in offsetting the change in the hedged cash flows of the underlying exposure is deferred in Accumulated Other Comprehensive Income (Loss) until earnings are affected by the variability of cash flows of the hedged transaction. Any hedge ineffectiveness is included in current period earnings. For derivative contracts that do not qualify or are not designated as cash flow or fair value hedges or as NPNS, changes in fair value are recorded in current period earnings. PSEG does not currently elect fair value or cash flow hedge accounting on its commodity derivative positions. Contracts that qualify for, and are designated, as NPNS are accounted for upon settlement. Contracts which qualify for NPNS are contracts for which physical delivery is probable, they will not be financially settled, and the quantities under contract are expected to be used or sold in the normal course of business over a reasonable period of time. For additional information regarding derivative financial instruments, see Note 17. Financial Risk Management Activities . Revenue Recognition PSE&G’s regulated electric and gas revenues are recorded primarily based on services rendered to customers. PSE&G records unbilled revenues for the estimated amount customers will be billed for services rendered from the time meters were last read to the end of the respective accounting period. The unbilled revenue is estimated each month based on usage per day, the number of unbilled days in the period, estimated seasonal loads based upon the time of year and the variance of actual degree-days and temperature-humidity-index hours of the unbilled period from expected norms. Regulated revenues from the transmission of electricity are recognized as services are provided based on a FERC-approved annual formula rate mechanism. This mechanism provides for an annual filing of estimated revenue requirement with rates effective January 1 of each year. After completion of the annual period ending December 31, PSE&G files a true-up whereby it compares its actual revenue requirement to the original estimate to determine any over or under collection of revenue. PSE&G records the estimated financial statement impact of the difference between the actual and the filed revenue requirement as a refund or deferral for future recovery when such amounts are probable and can be reasonably estimated in accordance with accounting guidance for rate-regulated entities. The majority of Power’s revenues relate to bilateral contracts, which are accounted for on the accrual basis as the energy is delivered. Power’s revenue also includes changes in the value of energy derivative contracts that are not designated as NPNS. See Note 17. Financial Risk Management Activities for further discussion. PJM Interconnection, L.L.C. (PJM), the Independent System Operator-New England (ISO-NE) and the New York Independent System Operator (NYISO) facilitate the dispatch of energy and energy-related products. Power generally reports electricity sales and purchases conducted with those individual ISOs on a net hourly basis in either Revenues or Energy Costs in its Consolidated Statement of Operations, the classification of which depends on the net hourly activity. Capacity revenue and expense is also reported net based on Power’s monthly net sale or purchase position in the individual ISOs. PSEG LI is the primary beneficiary of Long Island Electric Utility Servco, LLC (Servco). For transactions in which Servco acts as principal, Servco records revenues and the related pass-through expenditures separately in Operating Revenues and Operations and Maintenance (O&M) Expense, respectively. See Note 5. Variable Interest Entity for further information. The majority of Energy Holdings' revenues relate to its investments in leveraged leases. Income on leveraged leases is recognized by a method which produces a constant rate of return on the outstanding net investment in the lease, net of the related deferred tax liability, in the years in which the net investment is positive. Any gains or losses incurred as a result of a lease termination are recorded as revenues as these events occur in the ordinary course of business of managing the investment portfolio. For additional information regarding Revenues, see Note 3. Revenues . Depreciation and Amortization (D&A) PSE&G calculates depreciation under the straight-line method based on estimated average remaining lives of the several classes of depreciable property. These estimates are reviewed on a periodic basis and necessary adjustments are made as approved by the BPU or FERC. The depreciation rate stated as a percentage of original cost of depreciable property was as follows: 2018 2017 2016 Avg Rate Avg Rate Avg Rate Electric Transmission 2.42 % 2.41 % 2.39 % Electric Distribution 2.51 % 2.51 % 2.49 % Gas Distribution 1.61 % 1.63 % 1.63 % Power calculates depreciation on generation-related assets under the straight-line method based on the assets’ estimated useful lives. The estimated useful lives are: • general plant assets— 3 years to 20 years • fossil production assets— 30 years to 67 years • nuclear generation assets—approximately 60 years • pumped storage facilities— 76 years • solar assets— 25 years Allowance for Funds Used During Construction (AFUDC) and Interest Capitalized During Construction (IDC) AFUDC represents the cost of debt and equity funds used to finance the construction of new utility assets at PSE&G. IDC represents the cost of debt used to finance construction at Power. The amount of AFUDC or IDC capitalized as Property, Plant and Equipment is included as a reduction of interest charges or other income for the equity portion. The amounts and average rates used to calculate AFUDC or IDC for the years ended December 31, 2018 , 2017 and 2016 were as follows: AFUDC/IDC Capitalized 2018 2017 2016 Millions Avg Rate Millions Avg Rate Millions Avg Rate PSE&G $ 70 7.74 % $ 73 7.42 % $ 66 7.81 % Power $ 67 4.60 % $ 78 4.60 % $ 54 4.87 % Income Taxes PSEG and its subsidiaries file a consolidated federal income tax return and income taxes are allocated to PSEG’s subsidiaries based on the taxable income or loss of each subsidiary on a separate return basis in accordance with a tax sharing agreement between PSEG and each of its affiliated subsidiaries. Allocations between PSEG and its subsidiaries are recorded through intercompany accounts. Investment tax credits deferred in prior years are being amortized over the useful lives of the related property. Uncertain income tax positions are accounted for using a benefit recognition model with a two-step approach, a more-likely-than-not recognition criterion and a measurement attribute that measures the position as the largest amount of tax benefit that is greater than 50% likely of being realized upon ultimate settlement. If it is not more-likely-than-not that the benefit will be sustained on its technical merits, no benefit will be recorded. Uncertain tax positions that relate only to timing of when an item is included on a tax return are considered to have met the recognition threshold. See Note 21. Income Taxes for further discussion. Impairment of Long-Lived Assets and Leveraged Leases Management evaluates long-lived assets for impairment whenever events or changes in circumstances, such as significant adverse changes in regulation, business climate, counterparty credit worthiness or market conditions, including prolonged periods of adverse commodity and capacity prices or a current expectation that a long-lived asset will be sold or disposed of significantly before the end of its previously estimated useful life, could potentially indicate an asset’s or asset group’s carrying amount may not be recoverable. In such an event, an undiscounted cash flow analysis is performed to determine if an impairment exists. When a long-lived asset’s or asset group’s carrying amount exceeds the associated undiscounted estimated future cash flows, the asset/asset group is considered impaired to the extent that its fair value is less than its carrying amount. An impairment would result in a reduction of the value of the long-lived asset/asset group through a non-cash charge to earnings. See Note 4. Early Plant Retirements for more information. For Power, cash flows for long-lived assets and asset groups are determined at the lowest level for which identifiable cash flows are largely independent of the cash flows of other assets and liabilities. The cash flows from the generation units are generally evaluated at a regional portfolio level (PJM, NYISO, ISO-NE) along with cash flows generated from the customer supply and risk management activities, inclusive of cash flows from contracts, including those that are accounted for as derivatives and meet the NPNS scope exception. In certain cases, generation assets are evaluated on an individual basis where those assets are individually contracted on a long-term basis with a third party and operations are independent of other generation assets (typically Power’s solar plants and Kalaeloa). Energy Holdings’ leveraged leases are comprised of Lease Receivables (net of non-recourse debt), the estimated residual value of leased assets, and unearned and deferred income. Residual values are the estimated values of the leased assets at the end of the respective lease per the original lease terms, net of any subsequent impairments. A review of the residual valuations, which are calculated by discounting the cash flows related to the leased assets after the lease term, is performed at least annually for each plant subject to lease using specific assumptions tailored to each plant. Those valuations are compared to the recorded residual values to determine if an impairment is warranted. Accounts Receivable—Allowance for Doubtful Accounts PSE&G’s accounts receivable are reported in the balance sheet as gross outstanding amounts adjusted for doubtful accounts. The allowance for doubtful accounts reflects PSE&G’s best estimates of losses on the accounts receivable balances. The allowance is based on accounts receivable aging, historical experience, write-off forecasts and other currently available evidence. Accounts receivable are charged off in the period in which the receivable is deemed uncollectible. Recoveries of accounts receivable are recorded when it is known they will be received. Materials and Supplies and Fuel PSE&G’s and Power’s materials and supplies are carried at average cost and charged to inventory when purchased and expensed or capitalized to Property, Plant and Equipment, as appropriate, when installed or used. Fuel inventory at Power is valued at the lower of average cost or market and includes stored natural gas, coal, fuel oil and propane used to generate power and to satisfy obligations under Power’s gas supply contracts with PSE&G. The costs of fuel, including initial transportation costs, are included in inventory when purchased and charged to Energy Costs when used or sold. The cost of nuclear fuel is capitalized within Property, Plant and Equipment and amortized to fuel expense using the units-of-production method. Property, Plant and Equipment PSE&G’s additions to and replacements of existing property, plant and equipment are capitalized at cost. The cost of maintenance, repair and replacement of minor items of property is charged to expense as incurred. At the time units of depreciable property are retired or otherwise disposed of, the original cost, adjusted for net salvage value, is charged to accumulated depreciation. Power capitalizes costs, including those related to its jointly-owned facilities, which increase the capacity, improve or extend the life of an existing asset, represent a newly acquired or constructed asset or represent the replacement of a retired asset. The cost of maintenance, repair and replacement of minor items of property is charged to appropriate expense accounts as incurred. Environmental costs are capitalized if the costs mitigate or prevent future environmental contamination or if the costs improve existing assets’ environmental safety or efficiency. All other environmental expenditures are expensed as incurred. Power also capitalizes spare parts that meet specific criteria. Capitalized spares are depreciated over the remaining lives of their associated assets. Trust Investments These securities comprise the Nuclear Decommissioning Trust (NDT) Fund, a master independent external trust account maintained to provide for the costs of decommissioning upon termination of operations of Power’s nuclear facilities and amounts that are deposited to fund a Rabbi Trust which was established to meet the obligations related to non-qualified pension plans and deferred compensation plans. Effective January 1, 2018, unrealized gains and losses on equity security investments are recorded in Net Income instead of Other Comprehensive Income (Loss). The debt securities continue to be classified as available-for-sale with the unrealized gains and losses recorded as a component of Accumulated Other Comprehensive Income (Loss). Realized gains and losses on both equity and available-for-sale debt security investments are recorded in earnings and are included with the unrealized gains and losses on equity securities in Net Gains (Losses) on Trust Investments. Other-than-temporary impairments on NDT and Rabbi Trust securities are also included in Net Gains (Losses) on Trust Investments. See Note 10. Trust Investments for further discussion. Pension and Other Postretirement Benefits (OPEB) Plans The market-related value of plan assets held for the qualified pension and OPEB plans is equal to the fair value of those assets as of year-end. Fair value is determined using quoted market prices and independent pricing services based upon the security type as reported by the trustee at the measurement date (December 31) for all plan assets. PSEG recognizes a long-term receivable primarily related to future funding by LIPA of Servco’s recognized pension and OPEB liabilities. This receivable is presented separately on the Consolidated Balance Sheet of PSEG as a noncurrent asset. Pursuant to the OSA, Servco records expense for contributions to its pension plan trusts and for OPEB payments made to retirees. See Note 13. Pension, Other Postretirement Benefits (OPEB) and Savings Plan for further discussion. Basis Adjustment PSE&G and Power have recorded a Basis Adjustment in their respective Consolidated Balance Sheets related to the generation assets that were transferred from PSE&G to Power in August 2000 at the price specified by the BPU. Because the transfer was between affiliates, the transaction was recorded at the net book value of the assets and liabilities rather than the transfer price. The difference between the total transfer price and the net book value of the generation-related assets and liabilities, $986 million , net of tax, was recorded as a Basis Adjustment on PSE&G’s and Power’s Consolidated Balance Sheets. The $986 million is an addition to PSE&G’s Common Stockholder’s Equity and a reduction of Power’s Member’s Equity. These amounts are eliminated on PSEG’s consolidated financial statements. Use of Estimates The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Recent Accounting Standards

Recent Accounting Standards	12 Months Ended
	Dec. 31, 2018
New Accounting Pronouncement [Line Items]
Recent Accounting Standards [Text Block]	Recent Accounting Standards New Standards Adopted in 2018 Revenue from Contracts With Customers — Accounting Standard Update (ASU) 2014-09, updated by ASUs 2015-14, 2016-08, 2016-10, 2016-12, 2016-20, 2017-13, 2017-14 This accounting standard, and related updates, were adopted on January 1, 2018 using the full retrospective transition method. There was no effect on Net Income as a result of adoption. However, certain retrospective adjustments were recorded in accordance with the new standard. At PSE&G, retrospective adjustments increased Operating Revenues by $90 million and $82 million , Energy Costs by $58 million and $77 million and O&M Expense by $32 million and $5 million for the years ended December 31, 2017 and 2016 , respectively. At Power, retrospective adjustments reduced Operating Revenues and Energy Costs by $70 million and $162 million for the years ended December 31, 2017 and 2016 , respectively. For disclosure requirements under this standard, including Nature of Goods and Services, Disaggregation of Revenues, and Remaining Performance Obligations under Fixed Consideration Contracts, see Note 3. Revenues . Recognition and Measurement of Financial Assets and Financial Liabilities—ASU 2016-01 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 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 adopted on January 1, 2018. Under the new guidance, equity investments in Power’s 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). 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 22. Accumulated Other Comprehensive Income (Loss), Net of Tax and Note 10. Trust Investments for further discussion. Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments—ASU 2016-15 This accounting standard reduces the diversity in practice in how certain cash receipts and cash payments are presented and classified in the Statement of Cash Flows. PSEG adopted this standard on January 1, 2018 using a retrospective transition method and had no changes in its presentation of its Statement of Cash Flows for each period presented. Statement of Cash Flows: Restricted Cash—ASU 2016-18 This accounting standard was adopted on 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 December 31, 2018 Consolidated Statements of Cash Flows was immaterial. Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (OPEB)—ASU 2017-07 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 year ended December 31, 2018 by approximately $58 million . The Consolidated Statements of Operations were recast to show retrospective adjustments of the non-service cost components of net benefit credits (costs) of $(8) million and $(15) million at PSE&G and $8 million and $(4) million at Power, for the years ended December 31, 2017 and 2016 , respectively, from O&M Expense to a new line item after Operating Income entitled Non-Operating Pension and OPEB Credits (Costs). See Note 13. Pension, Other Postretirement Benefits (OPEB) and Savings Plan . Stock Compensation - Scope of Modification Accounting—ASU 2017-09 This accounting standard was adopted on January 1, 2018. The standard will be applied prospectively to awards modified on or after January 1, 2018. There was no material impact on PSEG’s consolidated financial statements in 2018 from adoption of this new standard. New Standards Issued But Not Yet Adopted Leases — ASU 2016-02, updated by ASUs 2018-01, 2018-10, 2018-11 and 2018-20 This accounting standard, and related updates, replace existing lease accounting guidance and require lessees to recognize leases with a term greater than 12 months on the balance sheet using a right-of-use asset approach. At lease commencement, a lessee will recognize a lease asset and corresponding lease obligation. A lessee will classify its leases as either finance leases or operating leases and a lessor will classify its leases as operating leases, direct financing leases, or as sales-type leases. The standard requires additional disclosure of key information. Existing guidance related to leveraged leases does not change. Effective January 1, 2019, PSEG elected the prospective transition approach for all existing leases. There was no cumulative effect adjustment required to be recorded to Retained Earnings at adoption. P SEG elected various practical expedients allowed by the standard, including the package of three practical expedients related to not reassessing existing or expired contracts and initial direct costs; and excluding evaluation of land easements that exist or expired before adoption that were not previously accounted for as leases. The impact of adoption on PSEG’s Consolidated Balance Sheet was to increase its assets and liabilities by approximately $280 million . PSE&G’s assets and liabilities each increased by approximately $100 million and Power’s assets and liabilities each increased by approximately $50 million . PSEG’s adoption of this standard did not have a material impact on the Consolidated Statements of Operations or Consolidated Statements of Cash Flows of PSEG, PSE&G and Power. Derivatives and Hedging: Targeted Improvements to Accounting for Hedging Activities—ASU 2017-12, updated by ASU 2018-16 This accounting standard’s amendments more closely align hedge accounting with companies’ risk management activities in the financial statements and ease the operational burden of applying hedge accounting. The new guidance is effective for annual and interim periods beginning after December 15, 2018. PSEG adopted this standard on January 1, 2019. The standard requires using a modified retrospective method upon adoption. PSEG analyzed the impact of this standard on its consolidated financial statements and 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. Premium Amortization on Purchased Callable Debt Securities—ASU 2017-08 This accounting standard was issued to shorten the amortization period for certain callable debt securities held at a premium. Specifically, the standard requires the premium to be amortized to the earliest call date. The standard is effective for all entities for annual periods and interim periods within those annual periods beginning after December 15, 2018. PSEG adopted this standard on January 1, 2019 on a modified retrospective basis through a cumulative effect adjustment directly to Retained Earnings as of the beginning of 2019. Adoption of this standard did not have a material impact on PSEG’s financial statements. Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income—ASU 2018-02 This accounting standard affects any entity that is required to apply the provisions of the 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 allows entities to record a reclassification from Accumulated Other Comprehensive Income to Retained Earnings for stranded tax effects resulting from the recent decrease in the federal corporate income tax rate. The standard is effective for all entities for annual periods and interim periods within those annual periods beginning after December 15, 2018. PSEG adopted this standard on January 1, 2019. The impact of adoption on PSEG’s Consolidated Balance Sheet was to increase Retained Earnings and Accumulated Other Comprehensive Loss by approximately $81 million . Power’s Retained Earnings and Accumulated Other Comprehensive Loss increased by approximately $69 million . The impact on PSE&G’s Consolidated Balance Sheet was immaterial. PSEG’s adoption of this standard did not have a material impact on the Consolidated Statements of Operations or Consolidated Statements of Cash Flows of PSEG, PSE&G and Power. Measurement of Credit Losses on Financial Instruments — ASU 2016-13, updated by ASU 2018-19 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. Disclosure Framework — Changes to the Disclosure Requirements for Fair Value Measurement — ASU 2018-13 This accounting standard modifies the disclosure requirements for fair value measurements. Certain current disclosure requirements relating to Level 3 fair value measurements, and transfers between Level 1 and Level 2 fair value measurements will be eliminated. The standard will also add certain other disclosure requirements for Level 3 fair value measurements. The standard is effective for annual and interim periods beginning after December 15, 2019. Certain amendments in the standard should be applied prospectively for only the most recent interim or annual period presented in the initial fiscal year of adoption. All other amendments of the standard should be applied retrospectively to all periods presented upon their effective date. Early adoption is permitted. PSEG is currently analyzing the impact of this standard on its financial statements. Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract — ASU 2018-15 This accounting standard aligns the capitalization requirements for implementation costs incurred in a hosting arrangement that is a service contract with capitalization requirements for implementation costs incurred to develop or obtain internal-use software, including hosting arrangements that include an internal-use software license. The standard follows the guidance in ASC 350—Intangibles—Goodwill and Other to determine which implementation costs to capitalize as an asset related to the service contract and which costs to expense. The standard requires the amortization of capitalized costs to be presented in O&M Expense. In addition, the standard also adds presentation requirements for these costs in the statements of cash flows and financial position. The standard is effective for annual and interim periods beginning after December 15, 2019. Early adoption is permitted, including adoption in any interim period. This standard should be applied either retrospectively or prospectively to all implementation costs incurred after the date of adoption. PSEG is currently analyzing the impact of this standard on its financial statements. Targeted Improvements to Related Party Guidance for Variable Interest Entities (VIE) — ASU 2018-17 This accounting standard improves the VIE guidance in the area of decision-making fees. Consistent with how indirect interests held through related parties under common control are considered for determining whether a reporting entity must consolidate a VIE, indirect interests held through related parties in common control arrangements should be considered on a proportional basis for determining whether fees paid to decision makers and service providers are variable interests. This standard is effective for annual and interim periods beginning after December 15, 2019. The standard is required to be applied retrospectively with a cumulative-effect adjustment to retained earnings at the beginning of the earliest period presented. Early adoption is permitted. PSEG is currently analyzing the impact of this standard on 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 does not expect adoption of this standard to have a material impact on its financial statements. Disclosure Framework — Changes to the Disclosure Requirements for Defined Benefit Plans — ASU 2018-14 This accounting standard modifies the disclosure requirements for employers that sponsor defined benefit pension or other postretirement plans, including the elimination of certain current disclosure requirements. Certain other disclosure requirements related to interest crediting rates have been added and certain clarifications were made to other disclosure requirements. The standard is effective for fiscal years ending after December 15, 2020 and early adoption is permitted. An entity should apply the amendments in this standard on a retrospective basis to all periods presented. PSEG is currently analyzing the impact of this standard on its financial statements.
PSE&G [Member]
New Accounting Pronouncement [Line Items]
Recent Accounting Standards [Text Block]	Recent Accounting Standards New Standards Adopted in 2018 Revenue from Contracts With Customers — Accounting Standard Update (ASU) 2014-09, updated by ASUs 2015-14, 2016-08, 2016-10, 2016-12, 2016-20, 2017-13, 2017-14 This accounting standard, and related updates, were adopted on January 1, 2018 using the full retrospective transition method. There was no effect on Net Income as a result of adoption. However, certain retrospective adjustments were recorded in accordance with the new standard. At PSE&G, retrospective adjustments increased Operating Revenues by $90 million and $82 million , Energy Costs by $58 million and $77 million and O&M Expense by $32 million and $5 million for the years ended December 31, 2017 and 2016 , respectively. At Power, retrospective adjustments reduced Operating Revenues and Energy Costs by $70 million and $162 million for the years ended December 31, 2017 and 2016 , respectively. For disclosure requirements under this standard, including Nature of Goods and Services, Disaggregation of Revenues, and Remaining Performance Obligations under Fixed Consideration Contracts, see Note 3. Revenues . Recognition and Measurement of Financial Assets and Financial Liabilities—ASU 2016-01 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 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 adopted on January 1, 2018. Under the new guidance, equity investments in Power’s 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). 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 22. Accumulated Other Comprehensive Income (Loss), Net of Tax and Note 10. Trust Investments for further discussion. Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments—ASU 2016-15 This accounting standard reduces the diversity in practice in how certain cash receipts and cash payments are presented and classified in the Statement of Cash Flows. PSEG adopted this standard on January 1, 2018 using a retrospective transition method and had no changes in its presentation of its Statement of Cash Flows for each period presented. Statement of Cash Flows: Restricted Cash—ASU 2016-18 This accounting standard was adopted on 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 December 31, 2018 Consolidated Statements of Cash Flows was immaterial. Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (OPEB)—ASU 2017-07 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 year ended December 31, 2018 by approximately $58 million . The Consolidated Statements of Operations were recast to show retrospective adjustments of the non-service cost components of net benefit credits (costs) of $(8) million and $(15) million at PSE&G and $8 million and $(4) million at Power, for the years ended December 31, 2017 and 2016 , respectively, from O&M Expense to a new line item after Operating Income entitled Non-Operating Pension and OPEB Credits (Costs). See Note 13. Pension, Other Postretirement Benefits (OPEB) and Savings Plan . Stock Compensation - Scope of Modification Accounting—ASU 2017-09 This accounting standard was adopted on January 1, 2018. The standard will be applied prospectively to awards modified on or after January 1, 2018. There was no material impact on PSEG’s consolidated financial statements in 2018 from adoption of this new standard. New Standards Issued But Not Yet Adopted Leases — ASU 2016-02, updated by ASUs 2018-01, 2018-10, 2018-11 and 2018-20 This accounting standard, and related updates, replace existing lease accounting guidance and require lessees to recognize leases with a term greater than 12 months on the balance sheet using a right-of-use asset approach. At lease commencement, a lessee will recognize a lease asset and corresponding lease obligation. A lessee will classify its leases as either finance leases or operating leases and a lessor will classify its leases as operating leases, direct financing leases, or as sales-type leases. The standard requires additional disclosure of key information. Existing guidance related to leveraged leases does not change. Effective January 1, 2019, PSEG elected the prospective transition approach for all existing leases. There was no cumulative effect adjustment required to be recorded to Retained Earnings at adoption. P SEG elected various practical expedients allowed by the standard, including the package of three practical expedients related to not reassessing existing or expired contracts and initial direct costs; and excluding evaluation of land easements that exist or expired before adoption that were not previously accounted for as leases. The impact of adoption on PSEG’s Consolidated Balance Sheet was to increase its assets and liabilities by approximately $280 million . PSE&G’s assets and liabilities each increased by approximately $100 million and Power’s assets and liabilities each increased by approximately $50 million . PSEG’s adoption of this standard did not have a material impact on the Consolidated Statements of Operations or Consolidated Statements of Cash Flows of PSEG, PSE&G and Power. Derivatives and Hedging: Targeted Improvements to Accounting for Hedging Activities—ASU 2017-12, updated by ASU 2018-16 This accounting standard’s amendments more closely align hedge accounting with companies’ risk management activities in the financial statements and ease the operational burden of applying hedge accounting. The new guidance is effective for annual and interim periods beginning after December 15, 2018. PSEG adopted this standard on January 1, 2019. The standard requires using a modified retrospective method upon adoption. PSEG analyzed the impact of this standard on its consolidated financial statements and 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. Premium Amortization on Purchased Callable Debt Securities—ASU 2017-08 This accounting standard was issued to shorten the amortization period for certain callable debt securities held at a premium. Specifically, the standard requires the premium to be amortized to the earliest call date. The standard is effective for all entities for annual periods and interim periods within those annual periods beginning after December 15, 2018. PSEG adopted this standard on January 1, 2019 on a modified retrospective basis through a cumulative effect adjustment directly to Retained Earnings as of the beginning of 2019. Adoption of this standard did not have a material impact on PSEG’s financial statements. Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income—ASU 2018-02 This accounting standard affects any entity that is required to apply the provisions of the 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 allows entities to record a reclassification from Accumulated Other Comprehensive Income to Retained Earnings for stranded tax effects resulting from the recent decrease in the federal corporate income tax rate. The standard is effective for all entities for annual periods and interim periods within those annual periods beginning after December 15, 2018. PSEG adopted this standard on January 1, 2019. The impact of adoption on PSEG’s Consolidated Balance Sheet was to increase Retained Earnings and Accumulated Other Comprehensive Loss by approximately $81 million . Power’s Retained Earnings and Accumulated Other Comprehensive Loss increased by approximately $69 million . The impact on PSE&G’s Consolidated Balance Sheet was immaterial. PSEG’s adoption of this standard did not have a material impact on the Consolidated Statements of Operations or Consolidated Statements of Cash Flows of PSEG, PSE&G and Power. Measurement of Credit Losses on Financial Instruments — ASU 2016-13, updated by ASU 2018-19 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. Disclosure Framework — Changes to the Disclosure Requirements for Fair Value Measurement — ASU 2018-13 This accounting standard modifies the disclosure requirements for fair value measurements. Certain current disclosure requirements relating to Level 3 fair value measurements, and transfers between Level 1 and Level 2 fair value measurements will be eliminated. The standard will also add certain other disclosure requirements for Level 3 fair value measurements. The standard is effective for annual and interim periods beginning after December 15, 2019. Certain amendments in the standard should be applied prospectively for only the most recent interim or annual period presented in the initial fiscal year of adoption. All other amendments of the standard should be applied retrospectively to all periods presented upon their effective date. Early adoption is permitted. PSEG is currently analyzing the impact of this standard on its financial statements. Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract — ASU 2018-15 This accounting standard aligns the capitalization requirements for implementation costs incurred in a hosting arrangement that is a service contract with capitalization requirements for implementation costs incurred to develop or obtain internal-use software, including hosting arrangements that include an internal-use software license. The standard follows the guidance in ASC 350—Intangibles—Goodwill and Other to determine which implementation costs to capitalize as an asset related to the service contract and which costs to expense. The standard requires the amortization of capitalized costs to be presented in O&M Expense. In addition, the standard also adds presentation requirements for these costs in the statements of cash flows and financial position. The standard is effective for annual and interim periods beginning after December 15, 2019. Early adoption is permitted, including adoption in any interim period. This standard should be applied either retrospectively or prospectively to all implementation costs incurred after the date of adoption. PSEG is currently analyzing the impact of this standard on its financial statements. Targeted Improvements to Related Party Guidance for Variable Interest Entities (VIE) — ASU 2018-17 This accounting standard improves the VIE guidance in the area of decision-making fees. Consistent with how indirect interests held through related parties under common control are considered for determining whether a reporting entity must consolidate a VIE, indirect interests held through related parties in common control arrangements should be considered on a proportional basis for determining whether fees paid to decision makers and service providers are variable interests. This standard is effective for annual and interim periods beginning after December 15, 2019. The standard is required to be applied retrospectively with a cumulative-effect adjustment to retained earnings at the beginning of the earliest period presented. Early adoption is permitted. PSEG is currently analyzing the impact of this standard on 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 does not expect adoption of this standard to have a material impact on its financial statements. Disclosure Framework — Changes to the Disclosure Requirements for Defined Benefit Plans — ASU 2018-14 This accounting standard modifies the disclosure requirements for employers that sponsor defined benefit pension or other postretirement plans, including the elimination of certain current disclosure requirements. Certain other disclosure requirements related to interest crediting rates have been added and certain clarifications were made to other disclosure requirements. The standard is effective for fiscal years ending after December 15, 2020 and early adoption is permitted. An entity should apply the amendments in this standard on a retrospective basis to all periods presented. PSEG is currently analyzing the impact of this standard on its financial statements.
Power [Member]
New Accounting Pronouncement [Line Items]
Recent Accounting Standards [Text Block]	Recent Accounting Standards New Standards Adopted in 2018 Revenue from Contracts With Customers — Accounting Standard Update (ASU) 2014-09, updated by ASUs 2015-14, 2016-08, 2016-10, 2016-12, 2016-20, 2017-13, 2017-14 This accounting standard, and related updates, were adopted on January 1, 2018 using the full retrospective transition method. There was no effect on Net Income as a result of adoption. However, certain retrospective adjustments were recorded in accordance with the new standard. At PSE&G, retrospective adjustments increased Operating Revenues by $90 million and $82 million , Energy Costs by $58 million and $77 million and O&M Expense by $32 million and $5 million for the years ended December 31, 2017 and 2016 , respectively. At Power, retrospective adjustments reduced Operating Revenues and Energy Costs by $70 million and $162 million for the years ended December 31, 2017 and 2016 , respectively. For disclosure requirements under this standard, including Nature of Goods and Services, Disaggregation of Revenues, and Remaining Performance Obligations under Fixed Consideration Contracts, see Note 3. Revenues . Recognition and Measurement of Financial Assets and Financial Liabilities—ASU 2016-01 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 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 adopted on January 1, 2018. Under the new guidance, equity investments in Power’s 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). 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 22. Accumulated Other Comprehensive Income (Loss), Net of Tax and Note 10. Trust Investments for further discussion. Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments—ASU 2016-15 This accounting standard reduces the diversity in practice in how certain cash receipts and cash payments are presented and classified in the Statement of Cash Flows. PSEG adopted this standard on January 1, 2018 using a retrospective transition method and had no changes in its presentation of its Statement of Cash Flows for each period presented. Statement of Cash Flows: Restricted Cash—ASU 2016-18 This accounting standard was adopted on 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 December 31, 2018 Consolidated Statements of Cash Flows was immaterial. Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (OPEB)—ASU 2017-07 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 year ended December 31, 2018 by approximately $58 million . The Consolidated Statements of Operations were recast to show retrospective adjustments of the non-service cost components of net benefit credits (costs) of $(8) million and $(15) million at PSE&G and $8 million and $(4) million at Power, for the years ended December 31, 2017 and 2016 , respectively, from O&M Expense to a new line item after Operating Income entitled Non-Operating Pension and OPEB Credits (Costs). See Note 13. Pension, Other Postretirement Benefits (OPEB) and Savings Plan . Stock Compensation - Scope of Modification Accounting—ASU 2017-09 This accounting standard was adopted on January 1, 2018. The standard will be applied prospectively to awards modified on or after January 1, 2018. There was no material impact on PSEG’s consolidated financial statements in 2018 from adoption of this new standard. New Standards Issued But Not Yet Adopted Leases — ASU 2016-02, updated by ASUs 2018-01, 2018-10, 2018-11 and 2018-20 This accounting standard, and related updates, replace existing lease accounting guidance and require lessees to recognize leases with a term greater than 12 months on the balance sheet using a right-of-use asset approach. At lease commencement, a lessee will recognize a lease asset and corresponding lease obligation. A lessee will classify its leases as either finance leases or operating leases and a lessor will classify its leases as operating leases, direct financing leases, or as sales-type leases. The standard requires additional disclosure of key information. Existing guidance related to leveraged leases does not change. Effective January 1, 2019, PSEG elected the prospective transition approach for all existing leases. There was no cumulative effect adjustment required to be recorded to Retained Earnings at adoption. P SEG elected various practical expedients allowed by the standard, including the package of three practical expedients related to not reassessing existing or expired contracts and initial direct costs; and excluding evaluation of land easements that exist or expired before adoption that were not previously accounted for as leases. The impact of adoption on PSEG’s Consolidated Balance Sheet was to increase its assets and liabilities by approximately $280 million . PSE&G’s assets and liabilities each increased by approximately $100 million and Power’s assets and liabilities each increased by approximately $50 million . PSEG’s adoption of this standard did not have a material impact on the Consolidated Statements of Operations or Consolidated Statements of Cash Flows of PSEG, PSE&G and Power. Derivatives and Hedging: Targeted Improvements to Accounting for Hedging Activities—ASU 2017-12, updated by ASU 2018-16 This accounting standard’s amendments more closely align hedge accounting with companies’ risk management activities in the financial statements and ease the operational burden of applying hedge accounting. The new guidance is effective for annual and interim periods beginning after December 15, 2018. PSEG adopted this standard on January 1, 2019. The standard requires using a modified retrospective method upon adoption. PSEG analyzed the impact of this standard on its consolidated financial statements and 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. Premium Amortization on Purchased Callable Debt Securities—ASU 2017-08 This accounting standard was issued to shorten the amortization period for certain callable debt securities held at a premium. Specifically, the standard requires the premium to be amortized to the earliest call date. The standard is effective for all entities for annual periods and interim periods within those annual periods beginning after December 15, 2018. PSEG adopted this standard on January 1, 2019 on a modified retrospective basis through a cumulative effect adjustment directly to Retained Earnings as of the beginning of 2019. Adoption of this standard did not have a material impact on PSEG’s financial statements. Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income—ASU 2018-02 This accounting standard affects any entity that is required to apply the provisions of the 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 allows entities to record a reclassification from Accumulated Other Comprehensive Income to Retained Earnings for stranded tax effects resulting from the recent decrease in the federal corporate income tax rate. The standard is effective for all entities for annual periods and interim periods within those annual periods beginning after December 15, 2018. PSEG adopted this standard on January 1, 2019. The impact of adoption on PSEG’s Consolidated Balance Sheet was to increase Retained Earnings and Accumulated Other Comprehensive Loss by approximately $81 million . Power’s Retained Earnings and Accumulated Other Comprehensive Loss increased by approximately $69 million . The impact on PSE&G’s Consolidated Balance Sheet was immaterial. PSEG’s adoption of this standard did not have a material impact on the Consolidated Statements of Operations or Consolidated Statements of Cash Flows of PSEG, PSE&G and Power. Measurement of Credit Losses on Financial Instruments — ASU 2016-13, updated by ASU 2018-19 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. Disclosure Framework — Changes to the Disclosure Requirements for Fair Value Measurement — ASU 2018-13 This accounting standard modifies the disclosure requirements for fair value measurements. Certain current disclosure requirements relating to Level 3 fair value measurements, and transfers between Level 1 and Level 2 fair value measurements will be eliminated. The standard will also add certain other disclosure requirements for Level 3 fair value measurements. The standard is effective for annual and interim periods beginning after December 15, 2019. Certain amendments in the standard should be applied prospectively for only the most recent interim or annual period presented in the initial fiscal year of adoption. All other amendments of the standard should be applied retrospectively to all periods presented upon their effective date. Early adoption is permitted. PSEG is currently analyzing the impact of this standard on its financial statements. Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract — ASU 2018-15 This accounting standard aligns the capitalization requirements for implementation costs incurred in a hosting arrangement that is a service contract with capitalization requirements for implementation costs incurred to develop or obtain internal-use software, including hosting arrangements that include an internal-use software license. The standard follows the guidance in ASC 350—Intangibles—Goodwill and Other to determine which implementation costs to capitalize as an asset related to the service contract and which costs to expense. The standard requires the amortization of capitalized costs to be presented in O&M Expense. In addition, the standard also adds presentation requirements for these costs in the statements of cash flows and financial position. The standard is effective for annual and interim periods beginning after December 15, 2019. Early adoption is permitted, including adoption in any interim period. This standard should be applied either retrospectively or prospectively to all implementation costs incurred after the date of adoption. PSEG is currently analyzing the impact of this standard on its financial statements. Targeted Improvements to Related Party Guidance for Variable Interest Entities (VIE) — ASU 2018-17 This accounting standard improves the VIE guidance in the area of decision-making fees. Consistent with how indirect interests held through related parties under common control are considered for determining whether a reporting entity must consolidate a VIE, indirect interests held through related parties in common control arrangements should be considered on a proportional basis for determining whether fees paid to decision makers and service providers are variable interests. This standard is effective for annual and interim periods beginning after December 15, 2019. The standard is required to be applied retrospectively with a cumulative-effect adjustment to retained earnings at the beginning of the earliest period presented. Early adoption is permitted. PSEG is currently analyzing the impact of this standard on 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 does not expect adoption of this standard to have a material impact on its financial statements. Disclosure Framework — Changes to the Disclosure Requirements for Defined Benefit Plans — ASU 2018-14 This accounting standard modifies the disclosure requirements for employers that sponsor defined benefit pension or other postretirement plans, including the elimination of certain current disclosure requirements. Certain other disclosure requirements related to interest crediting rates have been added and certain clarifications were made to other disclosure requirements. The standard is effective for fiscal years ending after December 15, 2020 and early adoption is permitted. An entity should apply the amendments in this standard on a retrospective basis to all periods presented. PSEG is currently analyzing the impact of this standard on its financial statements.

Revenues Revenues

Revenues Revenues	12 Months Ended
	Dec. 31, 2018
Revenues	Revenues Nature of Goods and Services The following is a description of principal activities by reportable segment from which PSEG, PSE&G and Power generate their revenues. PSE&G Revenues from Contracts with Customers Electric and Gas Distribution and Transmission Revenues —PSE&G sells gas and electricity to customers under default commodity supply tariffs. PSE&G’s regulated electric and gas default commodity supply and distribution services are separate tariffs which are satisfied as the product(s) and/or services are delivered to the customer. The electric and gas commodity and delivery tariffs are recurring contracts in effect until cancellation by the customer. Revenue is recognized over time as the service is rendered to the customer. Included in PSE&G’s regulated revenues are unbilled electric and gas revenues which represent the estimated amount customers will be billed for services rendered from the most recent meter reading to the end of the respective accounting period. PSE&G’s transmission revenues are earned under a separate FERC tariff. The performance obligation of transmission service is satisfied over time as it is provided to and consumed by the 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 true-up mechanism is an alternative revenue which is outside the scope of revenue from contracts with customers. Other Revenues from Contracts with Customers Other revenues from contracts with customers, which are not a material source of PSE&G revenues, are generated primarily from appliance repair services and solar generation projects. The performance obligations under these contracts are satisfied and revenue is recognized as control of products is delivered or services are rendered. Payment for services rendered and products transferred are typically due within 30 days of month of delivery. Revenues Unrelated to Contracts with Customers Other PSE&G revenues unrelated to contracts with customers are derived from alternative revenue mechanisms recorded pursuant to regulatory accounting guidance. These revenues, which include weather normalization, green energy program true-ups and transmission formula rate true-ups, are not a material source of PSE&G revenues. Power Revenues from Contracts with Customers 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, remains in effect 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. Other Revenues from Contracts with Customers 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. Revenues Unrelated to Contracts with Customers Power’s revenues unrelated to contracts with customers include electric, gas and certain energy-related transactions accounted for in accordance with Derivatives and Hedging accounting guidance. See Note 17. Financial Risk Management Activities for further discussion. Power is also a party to solar contracts that qualify as leases and are accounted for in accordance with lease accounting guidance. Other Revenues from Contracts with Customers PSEG LI has a contract with LIPA which generates revenues. PSEG LI’s subsidiary, Servco records costs which are recovered from LIPA and records the recovery of those costs as revenues when Servco is a principal in the transaction. Revenues Unrelated to Contracts with Customers Energy Holdings generates lease revenues which are recorded pursuant to lease accounting guidance. Disaggregation of Revenues PSE&G Power Other Eliminations Consolidated Millions Year Ended December 31, 2018 Revenues from Contracts with Customers Electric Distribution $ 3,131 $ — $ — $ — $ 3,131 Gas Distribution 1,756 — — (18 ) 1,738 Transmission 1,236 — — — 1,236 Electricity and Related Product Sales PJM Third Party Sales — 1,933 — — 1,933 Sales to Affiliates — 609 — (609 ) — New York ISO — 209 — — 209 ISO New England — 92 — — 92 Gas Sales Third Party Sales — 151 — — 151 Sales to Affiliates — 861 — (861 ) — Other Revenues from Contracts with Customers (A) 275 44 532 (4 ) 847 Total Revenues from Contracts with Customers 6,398 3,899 532 (1,492 ) 9,337 Revenues Unrelated to Contracts with Customers (B) 73 247 39 — 359 Total Operating Revenues $ 6,471 $ 4,146 $ 571 $ (1,492 ) $ 9,696 PSE&G Power Other Eliminations Consolidated Millions Year Ended December 31, 2017 Revenues from Contracts with Customers Electric Distribution $ 3,088 $ — $ — $ — $ 3,088 Gas Distribution 1,684 — — (14 ) 1,670 Transmission 1,222 — — — 1,222 Electricity and Related Product Sales PJM Third Party Sales — 1,199 — — 1,199 Sales to Affiliates — 734 — (734 ) — New York ISO — 181 — — 181 ISO New England — 39 — — 39 Gas Sales Third Party Sales — 134 — — 134 Sales to Affiliates — 804 — (804 ) — Other Revenues from Contracts with Customers (A) 265 42 511 (4 ) 814 Total Revenues from Contracts with Customers 6,259 3,133 511 (1,556 ) 8,347 Revenues Unrelated to Contracts with Customers (B) 65 727 (45 ) — 747 Total Operating Revenues $ 6,324 $ 3,860 $ 466 $ (1,556 ) $ 9,094 PSE&G Power Other Eliminations Consolidated Millions Year Ended December 31, 2016 Revenues from Contracts with Customers Electric Distribution $ 3,327 $ — $ — $ — $ 3,327 Gas Distribution 1,582 — — (22 ) 1,560 Transmission 1,084 — — — 1,084 Electricity and Related Product Sales PJM Third Party Sales — 1,060 — — 1,060 Sales to Affiliates — 805 — (805 ) — New York ISO — 169 — — 169 ISO New England — 55 — — 55 Gas Sales Third Party Sales — 114 — — 114 Sales to Affiliates — 737 — (737 ) — Other Revenues from Contracts with Customers (A) 292 35 482 (4 ) 805 Total Revenues from Contracts with Customers 6,285 2,975 482 (1,568 ) 8,174 Revenues Unrelated to Contracts with Customers (B) 18 886 (112 ) — 792 Total Operating Revenues $ 6,303 $ 3,861 $ 370 $ (1,568 ) $ 8,966 (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 years ended December 31, 2018 , 2017 and 2016 , Other includes losses of $8 million , $77 million and $147 million , respectively, related to Energy Holdings’ investments in leases. For additional information, see Note 8. Long-Term Investments . Contract Balances PSE&G 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 December 31, 2018 and 2017 . Substantially all of PSE&G’s accounts receivable result from contracts with customers. Allowances represented approximately seven percent and six percent of accounts receivable as of December 31, 2018 and 2017 , respectively. Power Power generally collects consideration upon satisfaction of performance obligations, and therefore, Power had no material contract balances as of December 31, 2018 and 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 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. Other PSEG LI does not have any material contract balances as of December 31, 2018 and 2017 . Remaining Performance Obligations under Fixed Consideration Contracts 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: Power 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 satisfied resulting from the base and incremental auctions which have been completed: 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 Capacity Payments from the New England ISO Forward Capacity Market —The Forward Capacity Market (FCM) Auction is conducted annually three years in advance of the operating period. The table below includes Power’s cleared capacity in the FCM Auction 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 Bridgeport Harbor Station 3 in 2021. Power expects to realize the following average capacity prices for capacity obligations to be satisfied resulting from the FCM auctions which have been completed: Delivery Year $ per MW-Day MW Cleared June 2018 to May 2019 $314 820 June 2019 to May 2020 $231 1,330 June 2020 to May 2021 $195 1,330 June 2021 to May 2022 $192 950 June 2022 to May 2023 $231 480 June 2023 to May 2024 $231 480 June 2024 to May 2025 $231 480 June 2025 to May 2026 $231 480 Bilateral capacity contracts —Capacity obligations pursuant to contract terms through 2029 are anticipated to result in revenues totaling $170 million . Other The LIPA OSA is a 12 -year services contract ending in 2025 with annual fixed and incentive components. The fixed fee for the provision of services thereunder in 2018 is $64 million and could increase each year based on the change in the Consumer Price Index (CPI). The incentive for 2018 can range from zero to approximately $10 million and could increase each year thereafter based on the change in the CPI.
PSE&G [Member]
Revenues	Revenues Nature of Goods and Services The following is a description of principal activities by reportable segment from which PSEG, PSE&G and Power generate their revenues. PSE&G Revenues from Contracts with Customers Electric and Gas Distribution and Transmission Revenues —PSE&G sells gas and electricity to customers under default commodity supply tariffs. PSE&G’s regulated electric and gas default commodity supply and distribution services are separate tariffs which are satisfied as the product(s) and/or services are delivered to the customer. The electric and gas commodity and delivery tariffs are recurring contracts in effect until cancellation by the customer. Revenue is recognized over time as the service is rendered to the customer. Included in PSE&G’s regulated revenues are unbilled electric and gas revenues which represent the estimated amount customers will be billed for services rendered from the most recent meter reading to the end of the respective accounting period. PSE&G’s transmission revenues are earned under a separate FERC tariff. The performance obligation of transmission service is satisfied over time as it is provided to and consumed by the 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 true-up mechanism is an alternative revenue which is outside the scope of revenue from contracts with customers. Other Revenues from Contracts with Customers Other revenues from contracts with customers, which are not a material source of PSE&G revenues, are generated primarily from appliance repair services and solar generation projects. The performance obligations under these contracts are satisfied and revenue is recognized as control of products is delivered or services are rendered. Payment for services rendered and products transferred are typically due within 30 days of month of delivery. Revenues Unrelated to Contracts with Customers Other PSE&G revenues unrelated to contracts with customers are derived from alternative revenue mechanisms recorded pursuant to regulatory accounting guidance. These revenues, which include weather normalization, green energy program true-ups and transmission formula rate true-ups, are not a material source of PSE&G revenues. Power Revenues from Contracts with Customers 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, remains in effect 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. Other Revenues from Contracts with Customers 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. Revenues Unrelated to Contracts with Customers Power’s revenues unrelated to contracts with customers include electric, gas and certain energy-related transactions accounted for in accordance with Derivatives and Hedging accounting guidance. See Note 17. Financial Risk Management Activities for further discussion. Power is also a party to solar contracts that qualify as leases and are accounted for in accordance with lease accounting guidance. Other Revenues from Contracts with Customers PSEG LI has a contract with LIPA which generates revenues. PSEG LI’s subsidiary, Servco records costs which are recovered from LIPA and records the recovery of those costs as revenues when Servco is a principal in the transaction. Revenues Unrelated to Contracts with Customers Energy Holdings generates lease revenues which are recorded pursuant to lease accounting guidance. Disaggregation of Revenues PSE&G Power Other Eliminations Consolidated Millions Year Ended December 31, 2018 Revenues from Contracts with Customers Electric Distribution $ 3,131 $ — $ — $ — $ 3,131 Gas Distribution 1,756 — — (18 ) 1,738 Transmission 1,236 — — — 1,236 Electricity and Related Product Sales PJM Third Party Sales — 1,933 — — 1,933 Sales to Affiliates — 609 — (609 ) — New York ISO — 209 — — 209 ISO New England — 92 — — 92 Gas Sales Third Party Sales — 151 — — 151 Sales to Affiliates — 861 — (861 ) — Other Revenues from Contracts with Customers (A) 275 44 532 (4 ) 847 Total Revenues from Contracts with Customers 6,398 3,899 532 (1,492 ) 9,337 Revenues Unrelated to Contracts with Customers (B) 73 247 39 — 359 Total Operating Revenues $ 6,471 $ 4,146 $ 571 $ (1,492 ) $ 9,696 PSE&G Power Other Eliminations Consolidated Millions Year Ended December 31, 2017 Revenues from Contracts with Customers Electric Distribution $ 3,088 $ — $ — $ — $ 3,088 Gas Distribution 1,684 — — (14 ) 1,670 Transmission 1,222 — — — 1,222 Electricity and Related Product Sales PJM Third Party Sales — 1,199 — — 1,199 Sales to Affiliates — 734 — (734 ) — New York ISO — 181 — — 181 ISO New England — 39 — — 39 Gas Sales Third Party Sales — 134 — — 134 Sales to Affiliates — 804 — (804 ) — Other Revenues from Contracts with Customers (A) 265 42 511 (4 ) 814 Total Revenues from Contracts with Customers 6,259 3,133 511 (1,556 ) 8,347 Revenues Unrelated to Contracts with Customers (B) 65 727 (45 ) — 747 Total Operating Revenues $ 6,324 $ 3,860 $ 466 $ (1,556 ) $ 9,094 PSE&G Power Other Eliminations Consolidated Millions Year Ended December 31, 2016 Revenues from Contracts with Customers Electric Distribution $ 3,327 $ — $ — $ — $ 3,327 Gas Distribution 1,582 — — (22 ) 1,560 Transmission 1,084 — — — 1,084 Electricity and Related Product Sales PJM Third Party Sales — 1,060 — — 1,060 Sales to Affiliates — 805 — (805 ) — New York ISO — 169 — — 169 ISO New England — 55 — — 55 Gas Sales Third Party Sales — 114 — — 114 Sales to Affiliates — 737 — (737 ) — Other Revenues from Contracts with Customers (A) 292 35 482 (4 ) 805 Total Revenues from Contracts with Customers 6,285 2,975 482 (1,568 ) 8,174 Revenues Unrelated to Contracts with Customers (B) 18 886 (112 ) — 792 Total Operating Revenues $ 6,303 $ 3,861 $ 370 $ (1,568 ) $ 8,966 (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 years ended December 31, 2018 , 2017 and 2016 , Other includes losses of $8 million , $77 million and $147 million , respectively, related to Energy Holdings’ investments in leases. For additional information, see Note 8. Long-Term Investments . Contract Balances PSE&G 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 December 31, 2018 and 2017 . Substantially all of PSE&G’s accounts receivable result from contracts with customers. Allowances represented approximately seven percent and six percent of accounts receivable as of December 31, 2018 and 2017 , respectively. Power Power generally collects consideration upon satisfaction of performance obligations, and therefore, Power had no material contract balances as of December 31, 2018 and 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 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. Other PSEG LI does not have any material contract balances as of December 31, 2018 and 2017 . Remaining Performance Obligations under Fixed Consideration Contracts 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: Power 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 satisfied resulting from the base and incremental auctions which have been completed: 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 Capacity Payments from the New England ISO Forward Capacity Market —The Forward Capacity Market (FCM) Auction is conducted annually three years in advance of the operating period. The table below includes Power’s cleared capacity in the FCM Auction 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 Bridgeport Harbor Station 3 in 2021. Power expects to realize the following average capacity prices for capacity obligations to be satisfied resulting from the FCM auctions which have been completed: Delivery Year $ per MW-Day MW Cleared June 2018 to May 2019 $314 820 June 2019 to May 2020 $231 1,330 June 2020 to May 2021 $195 1,330 June 2021 to May 2022 $192 950 June 2022 to May 2023 $231 480 June 2023 to May 2024 $231 480 June 2024 to May 2025 $231 480 June 2025 to May 2026 $231 480 Bilateral capacity contracts —Capacity obligations pursuant to contract terms through 2029 are anticipated to result in revenues totaling $170 million . Other The LIPA OSA is a 12 -year services contract ending in 2025 with annual fixed and incentive components. The fixed fee for the provision of services thereunder in 2018 is $64 million and could increase each year based on the change in the Consumer Price Index (CPI). The incentive for 2018 can range from zero to approximately $10 million and could increase each year thereafter based on the change in the CPI.
Power [Member]
Revenues	Revenues Nature of Goods and Services The following is a description of principal activities by reportable segment from which PSEG, PSE&G and Power generate their revenues. PSE&G Revenues from Contracts with Customers Electric and Gas Distribution and Transmission Revenues —PSE&G sells gas and electricity to customers under default commodity supply tariffs. PSE&G’s regulated electric and gas default commodity supply and distribution services are separate tariffs which are satisfied as the product(s) and/or services are delivered to the customer. The electric and gas commodity and delivery tariffs are recurring contracts in effect until cancellation by the customer. Revenue is recognized over time as the service is rendered to the customer. Included in PSE&G’s regulated revenues are unbilled electric and gas revenues which represent the estimated amount customers will be billed for services rendered from the most recent meter reading to the end of the respective accounting period. PSE&G’s transmission revenues are earned under a separate FERC tariff. The performance obligation of transmission service is satisfied over time as it is provided to and consumed by the 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 true-up mechanism is an alternative revenue which is outside the scope of revenue from contracts with customers. Other Revenues from Contracts with Customers Other revenues from contracts with customers, which are not a material source of PSE&G revenues, are generated primarily from appliance repair services and solar generation projects. The performance obligations under these contracts are satisfied and revenue is recognized as control of products is delivered or services are rendered. Payment for services rendered and products transferred are typically due within 30 days of month of delivery. Revenues Unrelated to Contracts with Customers Other PSE&G revenues unrelated to contracts with customers are derived from alternative revenue mechanisms recorded pursuant to regulatory accounting guidance. These revenues, which include weather normalization, green energy program true-ups and transmission formula rate true-ups, are not a material source of PSE&G revenues. Power Revenues from Contracts with Customers 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, remains in effect 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. Other Revenues from Contracts with Customers 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. Revenues Unrelated to Contracts with Customers Power’s revenues unrelated to contracts with customers include electric, gas and certain energy-related transactions accounted for in accordance with Derivatives and Hedging accounting guidance. See Note 17. Financial Risk Management Activities for further discussion. Power is also a party to solar contracts that qualify as leases and are accounted for in accordance with lease accounting guidance. Other Revenues from Contracts with Customers PSEG LI has a contract with LIPA which generates revenues. PSEG LI’s subsidiary, Servco records costs which are recovered from LIPA and records the recovery of those costs as revenues when Servco is a principal in the transaction. Revenues Unrelated to Contracts with Customers Energy Holdings generates lease revenues which are recorded pursuant to lease accounting guidance. Disaggregation of Revenues PSE&G Power Other Eliminations Consolidated Millions Year Ended December 31, 2018 Revenues from Contracts with Customers Electric Distribution $ 3,131 $ — $ — $ — $ 3,131 Gas Distribution 1,756 — — (18 ) 1,738 Transmission 1,236 — — — 1,236 Electricity and Related Product Sales PJM Third Party Sales — 1,933 — — 1,933 Sales to Affiliates — 609 — (609 ) — New York ISO — 209 — — 209 ISO New England — 92 — — 92 Gas Sales Third Party Sales — 151 — — 151 Sales to Affiliates — 861 — (861 ) — Other Revenues from Contracts with Customers (A) 275 44 532 (4 ) 847 Total Revenues from Contracts with Customers 6,398 3,899 532 (1,492 ) 9,337 Revenues Unrelated to Contracts with Customers (B) 73 247 39 — 359 Total Operating Revenues $ 6,471 $ 4,146 $ 571 $ (1,492 ) $ 9,696 PSE&G Power Other Eliminations Consolidated Millions Year Ended December 31, 2017 Revenues from Contracts with Customers Electric Distribution $ 3,088 $ — $ — $ — $ 3,088 Gas Distribution 1,684 — — (14 ) 1,670 Transmission 1,222 — — — 1,222 Electricity and Related Product Sales PJM Third Party Sales — 1,199 — — 1,199 Sales to Affiliates — 734 — (734 ) — New York ISO — 181 — — 181 ISO New England — 39 — — 39 Gas Sales Third Party Sales — 134 — — 134 Sales to Affiliates — 804 — (804 ) — Other Revenues from Contracts with Customers (A) 265 42 511 (4 ) 814 Total Revenues from Contracts with Customers 6,259 3,133 511 (1,556 ) 8,347 Revenues Unrelated to Contracts with Customers (B) 65 727 (45 ) — 747 Total Operating Revenues $ 6,324 $ 3,860 $ 466 $ (1,556 ) $ 9,094 PSE&G Power Other Eliminations Consolidated Millions Year Ended December 31, 2016 Revenues from Contracts with Customers Electric Distribution $ 3,327 $ — $ — $ — $ 3,327 Gas Distribution 1,582 — — (22 ) 1,560 Transmission 1,084 — — — 1,084 Electricity and Related Product Sales PJM Third Party Sales — 1,060 — — 1,060 Sales to Affiliates — 805 — (805 ) — New York ISO — 169 — — 169 ISO New England — 55 — — 55 Gas Sales Third Party Sales — 114 — — 114 Sales to Affiliates — 737 — (737 ) — Other Revenues from Contracts with Customers (A) 292 35 482 (4 ) 805 Total Revenues from Contracts with Customers 6,285 2,975 482 (1,568 ) 8,174 Revenues Unrelated to Contracts with Customers (B) 18 886 (112 ) — 792 Total Operating Revenues $ 6,303 $ 3,861 $ 370 $ (1,568 ) $ 8,966 (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 years ended December 31, 2018 , 2017 and 2016 , Other includes losses of $8 million , $77 million and $147 million , respectively, related to Energy Holdings’ investments in leases. For additional information, see Note 8. Long-Term Investments . Contract Balances PSE&G 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 December 31, 2018 and 2017 . Substantially all of PSE&G’s accounts receivable result from contracts with customers. Allowances represented approximately seven percent and six percent of accounts receivable as of December 31, 2018 and 2017 , respectively. Power Power generally collects consideration upon satisfaction of performance obligations, and therefore, Power had no material contract balances as of December 31, 2018 and 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 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. Other PSEG LI does not have any material contract balances as of December 31, 2018 and 2017 . Remaining Performance Obligations under Fixed Consideration Contracts 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: Power 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 satisfied resulting from the base and incremental auctions which have been completed: 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 Capacity Payments from the New England ISO Forward Capacity Market —The Forward Capacity Market (FCM) Auction is conducted annually three years in advance of the operating period. The table below includes Power’s cleared capacity in the FCM Auction 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 Bridgeport Harbor Station 3 in 2021. Power expects to realize the following average capacity prices for capacity obligations to be satisfied resulting from the FCM auctions which have been completed: Delivery Year $ per MW-Day MW Cleared June 2018 to May 2019 $314 820 June 2019 to May 2020 $231 1,330 June 2020 to May 2021 $195 1,330 June 2021 to May 2022 $192 950 June 2022 to May 2023 $231 480 June 2023 to May 2024 $231 480 June 2024 to May 2025 $231 480 June 2025 to May 2026 $231 480 Bilateral capacity contracts —Capacity obligations pursuant to contract terms through 2029 are anticipated to result in revenues totaling $170 million . Other The LIPA OSA is a 12 -year services contract ending in 2025 with annual fixed and incentive components. The fixed fee for the provision of services thereunder in 2018 is $64 million and could increase each year based on the change in the Consumer Price Index (CPI). The incentive for 2018 can range from zero to approximately $10 million and could increase each year thereafter based on the change in the CPI.

Early Plant Retirements Early P

Early Plant Retirements Early Plant Retirements	12 Months Ended
	Dec. 31, 2018
Restructuring Cost and Reserve [Line Items]
Early Plant Retirements [Text Block]	Early Plant Retirements Nuclear In May 2018, the governor of New Jersey signed legislation, referred to as the ZEC legislation, that recognizes that nuclear power is a critical component of New Jersey’s clean energy portfolio and an important element of a diverse energy generation portfolio that currently meets approximately 40 percent of New Jersey’s electric power needs. The ZEC legislation creates a Zero Emission Certificate (ZEC) program to be administered by the BPU. The BPU subsequently established processes to evaluate applications by qualified nuclear plants and to review and approve changes to the New Jersey’s electric distribution companies’ tariffs to provide for the purchase of ZECs from selected nuclear plants and recover those ZEC payments through a non-bypassable distribution charge (ZEC charge) in the amount of $0.004 per kilowatt-hour (which is equivalent to approximately $10 per MWh in payments to selected nuclear plants). ZECs will be awarded to selected nuclear plants, if any, in April 2019 at which time ZEC revenue would commence and would continue for approximately three years. Nuclear plants receiving ZEC payments will be obligated to maintain operations, subject to exceptions specified in the ZEC legislation. The ZEC legislation requires nuclear plants to reapply for any subsequent three year periods. The ZEC payment may be adjusted by the BPU (a) at any time to offset environmental or fuel diversity payments that a selected nuclear plant may receive from another source or (b) at certain times specified in the ZEC legislation if the BPU determines that the purposes of the ZEC legislation can be achieved through a reduced charge that will nonetheless be sufficient to achieve the state’s air quality and other environmental objectives by preventing the retirement of nuclear plants. In December 2018, Power submitted applications to the BPU for the Salem 1 and 2 and Hope Creek nuclear plants. These were the only applications received by the BPU. As required, Power’s three applications each included a certification pursuant to which Power confirmed that each of the Salem 1, Salem 2 and Hope Creek plants will cease operations within three years absent a material financial change. Power’s submittal further attested that the nuclear plants are not expected to cover their costs and operating and market risks as defined in the ZEC legislation, absent a material financial change. As a result, absent a material financial change, Power will retire all three plants unless all of the plants receive ZECs. Power operates its nuclear plants as an interdependent fleet on a common site with shared costs and services, which allows them to achieve economies of scale. A decision to retire one nuclear plant would also adversely impact Power’s ability to attract and retain qualified employees at its remaining plants. Power believes that the retirement of any individual nuclear plant would have the effect of decreasing the scale of its nuclear operations; however, the complex nature of operating nuclear plants would not decrease the attention required from management for the safe operation of the remaining nuclear operations. As a result, Power’s decision to retire any nuclear plant would be made at the site level and would result in the retirement of all of these New Jersey nuclear plants. Given the anticipated timing of the BPU’s decision on which nuclear plants, if any, have been selected to receive ZECs, which is expected in April 2019, in March 2019 Power will submit to the PJM Independent Market Monitor and the PJM Office of Interconnection a request for a preliminary exception to PJM’s RPM must-offer requirement with respect to Power’s interest for each of the Salem 1, Salem 2 and Hope Creek plants in connection with the 2022/2023 capacity auction expected to be held in August 2019. Power will also submit a deactivation notice to the extent that its filing deadline occurs prior to the award of ZECs by the BPU. If all of the Salem and Hope Creek plants are selected to receive ZECs, the preliminary exception and requested deactivation notice, as applicable, would be withdrawn. In the event that any of the Salem 1, Salem 2 and Hope Creek plants is not selected to receive ZEC payments in April 2019 by the BPU and do not otherwise experience a material financial change, Power will take all necessary steps to retire all of these plants at or prior to their refueling outages scheduled for the Fall 2019 in the case of Hope Creek, Spring 2020 in the case of Salem 2 and Fall 2020 in the case of Salem 1. Alternatively, if all of the Salem 1, Salem 2 and Hope Creek plants are selected to receive ZEC payments in April 2019 but the financial condition of the plants is materially adversely impacted by potential changes to the capacity market construct being considered by FERC (absent sufficient capacity revenues provided under a program approved by the BPU in accordance with a FERC authorized capacity mechanism), Power would still take all necessary steps to retire all of these plants. The costs and accounting charges associated with any such retirement, which may include, among other things, accelerated D&A or impairment charges, potential penalties associated with the early termination of capacity obligations and fuel contracts, accelerated asset retirement costs, severance costs, environmental remediation costs and, in certain circumstances, potential additional funding of the NDT Fund, would be material to both PSEG and Power. The following table provides the balance sheet amounts by generating station as of December 31, 2018 for significant assets and liabilities associated with Power’s owned share of its nuclear assets. As of December 31, 2018 Hope Creek Salem Support Facilities and Other (A) Peach Bottom Millions Assets Materials and Supplies Inventory $ 84 $ 65 $ — $ 41 Nuclear Production, net of Accumulated Depreciation 635 626 197 777 Nuclear Fuel In-Service, net of Accumulated Depreciation 139 110 — 148 Construction Work in Progress (including nuclear fuel) 131 132 5 20 Total Assets $ 989 $ 933 $ 202 $ 986 Liabilities Asset Retirement Obligation $ 253 $ 240 $ — $ 215 Total Liabilities $ 253 $ 240 $ — $ 215 Net Assets $ 736 $ 693 $ 202 $ 771 NRC License Renewal Term 2046 2036/2040 N/A 2033/2034 % Owned 100 % 57 % Various 50 % (A) Includes Hope Creek’s and Salem’s shared support facilities and other nuclear development capital. 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. In the latter half of 2016, PSEG and Power recognized pre-tax charges in Energy Costs and O&M of $62 million and $53 million , respectively, related to coal inventory adjustments, capacity penalties, materials and supplies inventory reserve adjustments for parts that cannot be used at other generating units, employee-related severance benefits costs and construction work in progress impairments, among other shutdown items. In addition to these charges, Power recognized D&A during 2016 of $571 million due to the significant shortening of the expected economic useful lives of Hudson and Mercer. During the year ended December 31, 2017 , Power recognized total D&A of $964 million for the Hudson and Mercer units to reflect the significant shortening of their expected economic useful lives. During the year ended December 31, 2017 , Power recognized pre-tax charges in Energy Costs of $15 million , primarily for coal inventory lower of cost or market adjustments. Power also recognized pre-tax charges in O&M of $23 million , including shut down costs and an increase in the Asset Retirement Obligation due to settlements and changes in cash flow estimates, partially offset by changes in employee-related severance costs. During the year ended December 31, 2018 , Power recognized pre-tax charges in Energy costs of $3 million for coal inventory lower of cost or market adjustments. In December 2018, Power completed the sale of the sites of the retired Hudson and Mercer units. Power transferred all land rights and structures on the sites to a third party purchaser, along with the assumption of the environmental liabilities for the sites. As a result of the sale and transfer of liabilities, Power recorded a pre-tax gain in 2018 of $54 million in O&M Expense. PSEG and Power continue to monitor their other coal assets, including their interest in 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.
Power [Member]
Restructuring Cost and Reserve [Line Items]
Early Plant Retirements [Text Block]	Early Plant Retirements Nuclear In May 2018, the governor of New Jersey signed legislation, referred to as the ZEC legislation, that recognizes that nuclear power is a critical component of New Jersey’s clean energy portfolio and an important element of a diverse energy generation portfolio that currently meets approximately 40 percent of New Jersey’s electric power needs. The ZEC legislation creates a Zero Emission Certificate (ZEC) program to be administered by the BPU. The BPU subsequently established processes to evaluate applications by qualified nuclear plants and to review and approve changes to the New Jersey’s electric distribution companies’ tariffs to provide for the purchase of ZECs from selected nuclear plants and recover those ZEC payments through a non-bypassable distribution charge (ZEC charge) in the amount of $0.004 per kilowatt-hour (which is equivalent to approximately $10 per MWh in payments to selected nuclear plants). ZECs will be awarded to selected nuclear plants, if any, in April 2019 at which time ZEC revenue would commence and would continue for approximately three years. Nuclear plants receiving ZEC payments will be obligated to maintain operations, subject to exceptions specified in the ZEC legislation. The ZEC legislation requires nuclear plants to reapply for any subsequent three year periods. The ZEC payment may be adjusted by the BPU (a) at any time to offset environmental or fuel diversity payments that a selected nuclear plant may receive from another source or (b) at certain times specified in the ZEC legislation if the BPU determines that the purposes of the ZEC legislation can be achieved through a reduced charge that will nonetheless be sufficient to achieve the state’s air quality and other environmental objectives by preventing the retirement of nuclear plants. In December 2018, Power submitted applications to the BPU for the Salem 1 and 2 and Hope Creek nuclear plants. These were the only applications received by the BPU. As required, Power’s three applications each included a certification pursuant to which Power confirmed that each of the Salem 1, Salem 2 and Hope Creek plants will cease operations within three years absent a material financial change. Power’s submittal further attested that the nuclear plants are not expected to cover their costs and operating and market risks as defined in the ZEC legislation, absent a material financial change. As a result, absent a material financial change, Power will retire all three plants unless all of the plants receive ZECs. Power operates its nuclear plants as an interdependent fleet on a common site with shared costs and services, which allows them to achieve economies of scale. A decision to retire one nuclear plant would also adversely impact Power’s ability to attract and retain qualified employees at its remaining plants. Power believes that the retirement of any individual nuclear plant would have the effect of decreasing the scale of its nuclear operations; however, the complex nature of operating nuclear plants would not decrease the attention required from management for the safe operation of the remaining nuclear operations. As a result, Power’s decision to retire any nuclear plant would be made at the site level and would result in the retirement of all of these New Jersey nuclear plants. Given the anticipated timing of the BPU’s decision on which nuclear plants, if any, have been selected to receive ZECs, which is expected in April 2019, in March 2019 Power will submit to the PJM Independent Market Monitor and the PJM Office of Interconnection a request for a preliminary exception to PJM’s RPM must-offer requirement with respect to Power’s interest for each of the Salem 1, Salem 2 and Hope Creek plants in connection with the 2022/2023 capacity auction expected to be held in August 2019. Power will also submit a deactivation notice to the extent that its filing deadline occurs prior to the award of ZECs by the BPU. If all of the Salem and Hope Creek plants are selected to receive ZECs, the preliminary exception and requested deactivation notice, as applicable, would be withdrawn. In the event that any of the Salem 1, Salem 2 and Hope Creek plants is not selected to receive ZEC payments in April 2019 by the BPU and do not otherwise experience a material financial change, Power will take all necessary steps to retire all of these plants at or prior to their refueling outages scheduled for the Fall 2019 in the case of Hope Creek, Spring 2020 in the case of Salem 2 and Fall 2020 in the case of Salem 1. Alternatively, if all of the Salem 1, Salem 2 and Hope Creek plants are selected to receive ZEC payments in April 2019 but the financial condition of the plants is materially adversely impacted by potential changes to the capacity market construct being considered by FERC (absent sufficient capacity revenues provided under a program approved by the BPU in accordance with a FERC authorized capacity mechanism), Power would still take all necessary steps to retire all of these plants. The costs and accounting charges associated with any such retirement, which may include, among other things, accelerated D&A or impairment charges, potential penalties associated with the early termination of capacity obligations and fuel contracts, accelerated asset retirement costs, severance costs, environmental remediation costs and, in certain circumstances, potential additional funding of the NDT Fund, would be material to both PSEG and Power. The following table provides the balance sheet amounts by generating station as of December 31, 2018 for significant assets and liabilities associated with Power’s owned share of its nuclear assets. As of December 31, 2018 Hope Creek Salem Support Facilities and Other (A) Peach Bottom Millions Assets Materials and Supplies Inventory $ 84 $ 65 $ — $ 41 Nuclear Production, net of Accumulated Depreciation 635 626 197 777 Nuclear Fuel In-Service, net of Accumulated Depreciation 139 110 — 148 Construction Work in Progress (including nuclear fuel) 131 132 5 20 Total Assets $ 989 $ 933 $ 202 $ 986 Liabilities Asset Retirement Obligation $ 253 $ 240 $ — $ 215 Total Liabilities $ 253 $ 240 $ — $ 215 Net Assets $ 736 $ 693 $ 202 $ 771 NRC License Renewal Term 2046 2036/2040 N/A 2033/2034 % Owned 100 % 57 % Various 50 % (A) Includes Hope Creek’s and Salem’s shared support facilities and other nuclear development capital. 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. In the latter half of 2016, PSEG and Power recognized pre-tax charges in Energy Costs and O&M of $62 million and $53 million , respectively, related to coal inventory adjustments, capacity penalties, materials and supplies inventory reserve adjustments for parts that cannot be used at other generating units, employee-related severance benefits costs and construction work in progress impairments, among other shutdown items. In addition to these charges, Power recognized D&A during 2016 of $571 million due to the significant shortening of the expected economic useful lives of Hudson and Mercer. During the year ended December 31, 2017 , Power recognized total D&A of $964 million for the Hudson and Mercer units to reflect the significant shortening of their expected economic useful lives. During the year ended December 31, 2017 , Power recognized pre-tax charges in Energy Costs of $15 million , primarily for coal inventory lower of cost or market adjustments. Power also recognized pre-tax charges in O&M of $23 million , including shut down costs and an increase in the Asset Retirement Obligation due to settlements and changes in cash flow estimates, partially offset by changes in employee-related severance costs. During the year ended December 31, 2018 , Power recognized pre-tax charges in Energy costs of $3 million for coal inventory lower of cost or market adjustments. In December 2018, Power completed the sale of the sites of the retired Hudson and Mercer units. Power transferred all land rights and structures on the sites to a third party purchaser, along with the assumption of the environmental liabilities for the sites. As a result of the sale and transfer of liabilities, Power recorded a pre-tax gain in 2018 of $54 million in O&M Expense. PSEG and Power continue to monitor their other coal assets, including their interest in 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.

Variable Interest Entities (VIE

Variable Interest Entities (VIEs)	12 Months Ended
	Dec. 31, 2018
Variable Interest Entity [Line Items]
Variable Interest Entities (VIEs) [Text Block]	Variable Interest Entity (VIE) VIE for which PSEG LI is the Primary Beneficiary PSEG LI consolidates Servco, a marginally capitalized VIE, which was created for the purpose of operating LIPA’s T&D system in Long Island, New York as well as providing administrative support functions to LIPA. PSEG LI is the primary beneficiary of Servco because it directs the operations of Servco, the activity that most significantly impacts Servco’s economic performance and it has the obligation to absorb losses of Servco that could potentially be significant to Servco. Such losses would be immaterial to PSEG. Pursuant to the OSA, Servco’s operating costs are reimbursable entirely by LIPA, and therefore, PSEG LI’s risk is limited related to the activities of Servco. PSEG LI has no current obligation to provide direct financial support to Servco. In addition to reimbursement of Servco’s operating costs as provided for in the OSA, PSEG LI receives an annual contract management fee. PSEG LI’s annual contractual management fee, in certain situations, could be partially offset by Servco’s annual storm costs not approved by the Federal Emergency Management Agency, limited contingent liabilities and penalties for failing to meet certain performance metrics. For transactions in which Servco acts as principal and controls the services provided to LIPA, such as transactions with its employees for labor and labor-related activities, including pension and OPEB-related transactions, Servco records revenues and the related pass-through expenditures separately in Operating Revenues and O&M Expense, respectively. In 2018 , 2017 and 2016 , Servco recorded $458 million , $438 million and $410 million , respectively, of O&M costs, the full reimbursement of which was reflected in Operating Revenues. For transactions in which Servco acts as an agent for LIPA, it records revenues and the related expenses on a net basis, resulting in no impact on PSEG’s Consolidated Statement of Operations.
PSE&G [Member]
Variable Interest Entity [Line Items]
Variable Interest Entities (VIEs) [Text Block]	Variable Interest Entity (VIE) VIE for which PSEG LI is the Primary Beneficiary PSEG LI consolidates Servco, a marginally capitalized VIE, which was created for the purpose of operating LIPA’s T&D system in Long Island, New York as well as providing administrative support functions to LIPA. PSEG LI is the primary beneficiary of Servco because it directs the operations of Servco, the activity that most significantly impacts Servco’s economic performance and it has the obligation to absorb losses of Servco that could potentially be significant to Servco. Such losses would be immaterial to PSEG. Pursuant to the OSA, Servco’s operating costs are reimbursable entirely by LIPA, and therefore, PSEG LI’s risk is limited related to the activities of Servco. PSEG LI has no current obligation to provide direct financial support to Servco. In addition to reimbursement of Servco’s operating costs as provided for in the OSA, PSEG LI receives an annual contract management fee. PSEG LI’s annual contractual management fee, in certain situations, could be partially offset by Servco’s annual storm costs not approved by the Federal Emergency Management Agency, limited contingent liabilities and penalties for failing to meet certain performance metrics. For transactions in which Servco acts as principal and controls the services provided to LIPA, such as transactions with its employees for labor and labor-related activities, including pension and OPEB-related transactions, Servco records revenues and the related pass-through expenditures separately in Operating Revenues and O&M Expense, respectively. In 2018 , 2017 and 2016 , Servco recorded $458 million , $438 million and $410 million , respectively, of O&M costs, the full reimbursement of which was reflected in Operating Revenues. For transactions in which Servco acts as an agent for LIPA, it records revenues and the related expenses on a net basis, resulting in no impact on PSEG’s Consolidated Statement of Operations.

Property, Plant And Equipment A

Property, Plant And Equipment And Jointly-Owned Facilities	12 Months Ended
	Dec. 31, 2018
Property, Plant and Equipment [Line Items]
Property Plant And Equipment And Jointly-Owned Facilities	Property, Plant and Equipment and Jointly-Owned Facilities Information related to Property, Plant and Equipment as of December 31, 2018 and 2017 is detailed below: PSE&G Power Other PSEG Consolidated Millions 2018 Transmission and Distribution: Electric Transmission $ 11,991 $ — $ — $ 11,991 Electric Distribution 8,989 — — 8,989 Gas Distribution and Transmission 7,854 — — 7,854 Construction Work in Progress 1,170 — — 1,170 Other 624 — — 624 Total Transmission and Distribution 30,628 — — 30,628 Generation: Fossil Production — 6,541 — 6,541 Nuclear Production — 2,971 — 2,971 Nuclear Fuel in Service — 765 — 765 Other Production-Solar 623 833 — 1,456 Construction Work in Progress — 1,011 — 1,011 Total Generation 623 12,121 — 12,744 Other 382 103 344 829 Total $ 31,633 $ 12,224 $ 344 $ 44,201 PSE&G Power Other PSEG Consolidated Millions 2017 Transmission and Distribution: Electric Transmission $ 10,425 $ — $ — $ 10,425 Electric Distribution 8,455 — — 8,455 Gas Distribution and Transmission 7,122 — — 7,122 Construction Work in Progress 1,735 — — 1,735 Other 512 — — 512 Total Transmission and Distribution 28,249 — — 28,249 Generation: Fossil Production — 4,923 — 4,923 Nuclear Production — 2,893 — 2,893 Nuclear Fuel in Service — 745 — 745 Other Production-Solar 593 757 — 1,350 Construction Work in Progress — 2,339 — 2,339 Total Generation 593 11,657 — 12,250 Other 275 98 359 732 Total $ 29,117 $ 11,755 $ 359 $ 41,231 As part of its solar production portfolio, Power owns and operates two California-based solar facilities with an aggregate capacity of approximately 30 MW direct current whose output is sold to Pacific Gas and Electric Company (PG&E) under power purchase agreements (PPAs) with twenty year terms. The net book value of these solar facilities was approximately $57 million as of December 31, 2018 . In January 2019, PG&E and its parent company PG&E Corporation filed for Chapter 11 bankruptcy protection. Power cannot predict the ultimate outcome that this bankruptcy proceeding will have on its ability to collect all of the future revenues from these facilities due under the PPAs; however, any adverse changes to the terms of Power’s PPAs as a result of this bankruptcy proceeding could result in the future impairment of these assets in amounts up to their current net book value. PSE&G and Power have ownership interests in and are responsible for providing their respective shares of the necessary financing for the following jointly-owned facilities to which they are a party. All amounts reflect PSE&G’s or Power’s share of the jointly-owned projects and the corresponding direct expenses are included in the Consolidated Statements of Operations as Operating Expenses. As of December 31, 2018 2017 Ownership Accumulated Accumulated Interest Plant Depreciation Plant Depreciation Millions PSE&G: Transmission Facilities Various $ 162 $ 58 $ 162 $ 58 Power: Coal Generating: Conemaugh 23 % $ 417 $ 192 $ 408 $ 178 Keystone 23 % $ 416 $ 200 $ 409 $ 187 Nuclear Generating: Peach Bottom 50 % $ 1,334 $ 389 $ 1,328 $ 348 Salem 57 % $ 1,196 $ 333 $ 1,147 $ 277 Nuclear Support Facilities Various $ 244 $ 95 $ 239 $ 81 Pumped Storage Facilities: Yards Creek 50 % $ 48 $ 26 $ 44 $ 26 Merrill Creek Reservoir 14 % $ 1 $ — $ 1 $ — Power holds undivided ownership interests in the jointly-owned facilities above. Power is entitled to shares of the generating capability and output of each unit equal to its respective ownership interests. Power also pays its ownership share of additional construction costs, fuel inventory purchases and operating expenses. Power’s share of expenses for the jointly-owned facilities is included in the appropriate expense category. Each owner is responsible for any financing with respect to its pro rata share of capital expenditures. Power co-owns Salem and Peach Bottom with Exelon Generation. Power is the operator of Salem and Exelon Generation is the operator of Peach Bottom. A committee appointed by the co-owners provides oversight. Proposed O&M budgets and requests for major capital expenditures are reviewed and approved as part of the normal Power governance process. GenOn Northeast Management Company is the operator for Keystone Generating Station and Conemaugh Generating Station. A committee appointed by the co-owners provides oversight. Proposed O&M budgets and requests for major capital expenditures are reviewed and approved as part of the normal Power governance process. Power is a co-owner in the Yards Creek Pumped Storage Generation Facility. Jersey Central Power & Light Company (JCP&L) is also a co-owner and the operator of this facility. JCP&L submits separate capital and O&M budgets, subject to Power’s approval as part of the normal Power governance process. Power is a minority owner in the Merrill Creek Reservoir and Environmental Preserve in Warren County, New Jersey. Merrill Creek Owners Group is the owner-operator of this facility. The operator submits separate capital and O&M budgets, subject to Power’s approval as part of the normal Power governance process.
PSE&G [Member]
Property, Plant and Equipment [Line Items]
Property Plant And Equipment And Jointly-Owned Facilities	Property, Plant and Equipment and Jointly-Owned Facilities Information related to Property, Plant and Equipment as of December 31, 2018 and 2017 is detailed below: PSE&G Power Other PSEG Consolidated Millions 2018 Transmission and Distribution: Electric Transmission $ 11,991 $ — $ — $ 11,991 Electric Distribution 8,989 — — 8,989 Gas Distribution and Transmission 7,854 — — 7,854 Construction Work in Progress 1,170 — — 1,170 Other 624 — — 624 Total Transmission and Distribution 30,628 — — 30,628 Generation: Fossil Production — 6,541 — 6,541 Nuclear Production — 2,971 — 2,971 Nuclear Fuel in Service — 765 — 765 Other Production-Solar 623 833 — 1,456 Construction Work in Progress — 1,011 — 1,011 Total Generation 623 12,121 — 12,744 Other 382 103 344 829 Total $ 31,633 $ 12,224 $ 344 $ 44,201 PSE&G Power Other PSEG Consolidated Millions 2017 Transmission and Distribution: Electric Transmission $ 10,425 $ — $ — $ 10,425 Electric Distribution 8,455 — — 8,455 Gas Distribution and Transmission 7,122 — — 7,122 Construction Work in Progress 1,735 — — 1,735 Other 512 — — 512 Total Transmission and Distribution 28,249 — — 28,249 Generation: Fossil Production — 4,923 — 4,923 Nuclear Production — 2,893 — 2,893 Nuclear Fuel in Service — 745 — 745 Other Production-Solar 593 757 — 1,350 Construction Work in Progress — 2,339 — 2,339 Total Generation 593 11,657 — 12,250 Other 275 98 359 732 Total $ 29,117 $ 11,755 $ 359 $ 41,231 As part of its solar production portfolio, Power owns and operates two California-based solar facilities with an aggregate capacity of approximately 30 MW direct current whose output is sold to Pacific Gas and Electric Company (PG&E) under power purchase agreements (PPAs) with twenty year terms. The net book value of these solar facilities was approximately $57 million as of December 31, 2018 . In January 2019, PG&E and its parent company PG&E Corporation filed for Chapter 11 bankruptcy protection. Power cannot predict the ultimate outcome that this bankruptcy proceeding will have on its ability to collect all of the future revenues from these facilities due under the PPAs; however, any adverse changes to the terms of Power’s PPAs as a result of this bankruptcy proceeding could result in the future impairment of these assets in amounts up to their current net book value. PSE&G and Power have ownership interests in and are responsible for providing their respective shares of the necessary financing for the following jointly-owned facilities to which they are a party. All amounts reflect PSE&G’s or Power’s share of the jointly-owned projects and the corresponding direct expenses are included in the Consolidated Statements of Operations as Operating Expenses. As of December 31, 2018 2017 Ownership Accumulated Accumulated Interest Plant Depreciation Plant Depreciation Millions PSE&G: Transmission Facilities Various $ 162 $ 58 $ 162 $ 58 Power: Coal Generating: Conemaugh 23 % $ 417 $ 192 $ 408 $ 178 Keystone 23 % $ 416 $ 200 $ 409 $ 187 Nuclear Generating: Peach Bottom 50 % $ 1,334 $ 389 $ 1,328 $ 348 Salem 57 % $ 1,196 $ 333 $ 1,147 $ 277 Nuclear Support Facilities Various $ 244 $ 95 $ 239 $ 81 Pumped Storage Facilities: Yards Creek 50 % $ 48 $ 26 $ 44 $ 26 Merrill Creek Reservoir 14 % $ 1 $ — $ 1 $ — Power holds undivided ownership interests in the jointly-owned facilities above. Power is entitled to shares of the generating capability and output of each unit equal to its respective ownership interests. Power also pays its ownership share of additional construction costs, fuel inventory purchases and operating expenses. Power’s share of expenses for the jointly-owned facilities is included in the appropriate expense category. Each owner is responsible for any financing with respect to its pro rata share of capital expenditures. Power co-owns Salem and Peach Bottom with Exelon Generation. Power is the operator of Salem and Exelon Generation is the operator of Peach Bottom. A committee appointed by the co-owners provides oversight. Proposed O&M budgets and requests for major capital expenditures are reviewed and approved as part of the normal Power governance process. GenOn Northeast Management Company is the operator for Keystone Generating Station and Conemaugh Generating Station. A committee appointed by the co-owners provides oversight. Proposed O&M budgets and requests for major capital expenditures are reviewed and approved as part of the normal Power governance process. Power is a co-owner in the Yards Creek Pumped Storage Generation Facility. Jersey Central Power & Light Company (JCP&L) is also a co-owner and the operator of this facility. JCP&L submits separate capital and O&M budgets, subject to Power’s approval as part of the normal Power governance process. Power is a minority owner in the Merrill Creek Reservoir and Environmental Preserve in Warren County, New Jersey. Merrill Creek Owners Group is the owner-operator of this facility. The operator submits separate capital and O&M budgets, subject to Power’s approval as part of the normal Power governance process.
Power [Member]
Property, Plant and Equipment [Line Items]
Property Plant And Equipment And Jointly-Owned Facilities	Property, Plant and Equipment and Jointly-Owned Facilities Information related to Property, Plant and Equipment as of December 31, 2018 and 2017 is detailed below: PSE&G Power Other PSEG Consolidated Millions 2018 Transmission and Distribution: Electric Transmission $ 11,991 $ — $ — $ 11,991 Electric Distribution 8,989 — — 8,989 Gas Distribution and Transmission 7,854 — — 7,854 Construction Work in Progress 1,170 — — 1,170 Other 624 — — 624 Total Transmission and Distribution 30,628 — — 30,628 Generation: Fossil Production — 6,541 — 6,541 Nuclear Production — 2,971 — 2,971 Nuclear Fuel in Service — 765 — 765 Other Production-Solar 623 833 — 1,456 Construction Work in Progress — 1,011 — 1,011 Total Generation 623 12,121 — 12,744 Other 382 103 344 829 Total $ 31,633 $ 12,224 $ 344 $ 44,201 PSE&G Power Other PSEG Consolidated Millions 2017 Transmission and Distribution: Electric Transmission $ 10,425 $ — $ — $ 10,425 Electric Distribution 8,455 — — 8,455 Gas Distribution and Transmission 7,122 — — 7,122 Construction Work in Progress 1,735 — — 1,735 Other 512 — — 512 Total Transmission and Distribution 28,249 — — 28,249 Generation: Fossil Production — 4,923 — 4,923 Nuclear Production — 2,893 — 2,893 Nuclear Fuel in Service — 745 — 745 Other Production-Solar 593 757 — 1,350 Construction Work in Progress — 2,339 — 2,339 Total Generation 593 11,657 — 12,250 Other 275 98 359 732 Total $ 29,117 $ 11,755 $ 359 $ 41,231 As part of its solar production portfolio, Power owns and operates two California-based solar facilities with an aggregate capacity of approximately 30 MW direct current whose output is sold to Pacific Gas and Electric Company (PG&E) under power purchase agreements (PPAs) with twenty year terms. The net book value of these solar facilities was approximately $57 million as of December 31, 2018 . In January 2019, PG&E and its parent company PG&E Corporation filed for Chapter 11 bankruptcy protection. Power cannot predict the ultimate outcome that this bankruptcy proceeding will have on its ability to collect all of the future revenues from these facilities due under the PPAs; however, any adverse changes to the terms of Power’s PPAs as a result of this bankruptcy proceeding could result in the future impairment of these assets in amounts up to their current net book value. PSE&G and Power have ownership interests in and are responsible for providing their respective shares of the necessary financing for the following jointly-owned facilities to which they are a party. All amounts reflect PSE&G’s or Power’s share of the jointly-owned projects and the corresponding direct expenses are included in the Consolidated Statements of Operations as Operating Expenses. As of December 31, 2018 2017 Ownership Accumulated Accumulated Interest Plant Depreciation Plant Depreciation Millions PSE&G: Transmission Facilities Various $ 162 $ 58 $ 162 $ 58 Power: Coal Generating: Conemaugh 23 % $ 417 $ 192 $ 408 $ 178 Keystone 23 % $ 416 $ 200 $ 409 $ 187 Nuclear Generating: Peach Bottom 50 % $ 1,334 $ 389 $ 1,328 $ 348 Salem 57 % $ 1,196 $ 333 $ 1,147 $ 277 Nuclear Support Facilities Various $ 244 $ 95 $ 239 $ 81 Pumped Storage Facilities: Yards Creek 50 % $ 48 $ 26 $ 44 $ 26 Merrill Creek Reservoir 14 % $ 1 $ — $ 1 $ — Power holds undivided ownership interests in the jointly-owned facilities above. Power is entitled to shares of the generating capability and output of each unit equal to its respective ownership interests. Power also pays its ownership share of additional construction costs, fuel inventory purchases and operating expenses. Power’s share of expenses for the jointly-owned facilities is included in the appropriate expense category. Each owner is responsible for any financing with respect to its pro rata share of capital expenditures. Power co-owns Salem and Peach Bottom with Exelon Generation. Power is the operator of Salem and Exelon Generation is the operator of Peach Bottom. A committee appointed by the co-owners provides oversight. Proposed O&M budgets and requests for major capital expenditures are reviewed and approved as part of the normal Power governance process. GenOn Northeast Management Company is the operator for Keystone Generating Station and Conemaugh Generating Station. A committee appointed by the co-owners provides oversight. Proposed O&M budgets and requests for major capital expenditures are reviewed and approved as part of the normal Power governance process. Power is a co-owner in the Yards Creek Pumped Storage Generation Facility. Jersey Central Power & Light Company (JCP&L) is also a co-owner and the operator of this facility. JCP&L submits separate capital and O&M budgets, subject to Power’s approval as part of the normal Power governance process. Power is a minority owner in the Merrill Creek Reservoir and Environmental Preserve in Warren County, New Jersey. Merrill Creek Owners Group is the owner-operator of this facility. The operator submits separate capital and O&M budgets, subject to Power’s approval as part of the normal Power governance process.

Regulatory Assets And Liabiliti

Regulatory Assets And Liabilities	12 Months Ended
	Dec. 31, 2018
Regulatory Assets And Liabilities [Line Items]
Regulatory Assets and Liabilities	Regulatory Assets and Liabilities PSE&G prepares its financial statements in accordance with GAAP for regulated utilities as described in Note 1. Organization, Basis of Presentation and Significant Accounting Policies . PSE&G has deferred certain costs based on rate orders issued by the BPU or FERC or based on PSE&G’s experience with prior rate proceedings. Most of PSE&G’s Regulatory Assets and Liabilities as of December 31, 2018 are supported by written orders, either explicitly or implicitly through the BPU’s treatment of various cost items. These costs will be recovered and amortized over various future periods. Regulatory Assets and other investments and costs incurred under our various infrastructure filings and clause mechanisms are subject to prudence reviews and can be disallowed in the future by regulatory authorities. To the extent that collection of any infrastructure or clause mechanism revenue, Regulatory Assets or payments of Regulatory Liabilities is no longer probable, the amounts would be charged or credited to income. PSE&G had the following Regulatory Assets and Liabilities: As of December 31, 2018 2017 Millions Regulatory Assets Current New Jersey Clean Energy Program $ 143 $ 128 Electric Energy Costs—Basic Generation Service (BGS) 115 23 Storm Damage and Other 56 — Green Program Recovery Charges (GPRC) 34 8 Weather Normalization Clause (WNC) 2 40 Other 39 12 Total Current Regulatory Assets $ 389 $ 211 Noncurrent Pension and OPEB Costs $ 1,090 $ 1,488 Deferred Income Tax Regulatory Assets 896 282 Manufactured Gas Plant (MGP) Remediation Costs 321 358 Electric Transmission and Gas Cost of Removal 223 199 Storm Damage and Other 214 241 Remediation Adjustment Charge (RAC) (Other Societal Benefits Charge (SBC)) 175 172 Asset Retirement Obligation 166 162 GPRC 95 98 Unamortized Loss on Reacquired Debt and Debt Expense 49 55 Gas Costs—BGSS 31 30 Other 139 137 Total Noncurrent Regulatory Assets $ 3,399 $ 3,222 Total Regulatory Assets $ 3,788 $ 3,433 As of December 31, 2018 2017 Millions Regulatory Liabilities Current Deferred Income Tax Regulatory Liabilities $ 299 $ — Gas Costs —BGSS — 30 Gas Margin Adjustment Clause 8 12 Other 4 5 Total Current Regulatory Liabilities $ 311 $ 47 Noncurrent Deferred Income Tax Regulatory Liabilities $ 3,170 $ 2,868 Electric Distribution Cost of Removal 51 80 Total Noncurrent Regulatory Liabilities $ 3,221 $ 2,948 Total Regulatory Liabilities $ 3,532 $ 2,995 All Regulatory Assets and Liabilities are excluded from PSE&G’s rate base unless otherwise noted. The Regulatory Assets and Liabilities in the table above are defined as follows: • Asset Retirement Obligation: These costs represent the differences between rate-regulated cost of removal accounting and asset retirement accounting under GAAP. These costs will be recovered in future rates as assets are retired. • Deferred Income Tax Regulatory Assets: These amounts represent the portion of deferred income taxes that will be recovered through future rates, based upon established regulatory practices and orders from the BPU. • Deferred Income Tax Regulatory Liabilities: These amounts represent the future refunds to customers of PSE&G’s excess Accumulated Deferred Income Tax liabilities as a result of the reduction in the federal corporate income tax rate effective January 1, 2018 and the flow-back of tax repair-related accumulated deferred income taxes that PSE&G agreed to as part of the settlement of its 2018 distribution base rate proceeding. • Electric and Gas Cost of Removal: PSE&G accrues and collects in rates for the cost of removing, dismantling and disposing of its T&D assets upon retirement. The Regulatory Asset or Liability for non-legally required cost of removal represents the difference between amounts collected in rates and costs actually incurred. • Electric Energy Costs — BGS: These costs represent the over or under recovered amounts associated with BGS, as approved by the BPU. Pursuant to BPU requirements, PSE&G serves as the supplier of last resort for electric customers within its service territory that are not served by another supplier. Pricing for those services are set by the BPU as a pass-through, resulting in no margin for PSE&G’s operations. Over or under recovered balances with interest are returned or recovered through monthly filings. • Gas Costs — BGSS: These costs represent the over or under recovered amounts associated with BGSS, as approved by the BPU. Pursuant to BPU requirements, PSE&G serves as the supplier of last resort for gas customers within its service territory that are not served by another supplier. Pricing for those services are set by the BPU as a pass-through, resulting in no margin for PSE&G’s operations. Over or under collected balances are returned or recovered through an annual filing. Interest is accrued only on over recovered balances. • Gas Margin Adjustment Clause: This mechanism credits Firm delivery customers for net distribution margin revenue collected from Transportation Gas Service Non-Firm (TSG-NF) delivery customers. The balance represents the difference between the net margin collected from the TSG-NF Customers versus bill credits provided to Firm delivery customers. Over or under recovered balances with interest are returned or recovered through the subsequent annual filing. • GPRC: This amount represents costs of the over or under collected balances associated with various renewable energy and energy efficiency programs. PSE&G files annually with the BPU for recovery of amounts that include a return on and of its investment over the lives of the underlying investments and capital assets which range from five to ten years. Interest is accrued monthly on any over or under recovered balances. Components of the GPRC include: Carbon Abatement, Energy Efficiency Economic Stimulus Program (EEE), EEE Extension Program, EEE Extension II Program, the Demand Response Program, Solar Generation Investment Program (Solar 4 All ® ), Solar 4 All ® Extension, Solar 4 All ® Extension II, Solar Loan II Program, Solar Loan III Program and the Energy Efficiency 2017 Program. • MGP Remediation Costs: Represents the low end of the range for the remaining environmental investigation and remediation program cleanup costs for MGPs that are probable of recovery in future rates. Once these costs are incurred, they are recovered through the RAC in the SBC over a seven year period with interest. • New Jersey Clean Energy Program: The BPU approved future funding requirements for Energy Efficiency and Renewable Energy Programs through the first half of 2018. The BPU funding requirements are recovered through the SBC. • Pension and OPEB Costs: Pursuant to the adoption of accounting guidance for employers’ defined benefit pension and OPEB plans, PSE&G recorded the unrecognized costs for defined benefit pension and other OPEB plans on the balance sheet as a Regulatory Asset. These costs represent actuarial gains or losses and prior service costs which have not been expensed. These costs are amortized and recovered in future rates. • RAC (Other SBC): Costs incurred to clean up MGPs which are recovered over seven years with interest through an annual filing. • SBC: The SBC, as authorized by the BPU and the New Jersey Electric Discount and Energy Competition Act, includes costs related to PSE&G’s electric and gas business as follows: (1) the Universal Service Fund (USF); (2) Energy Efficiency and Renewable Energy Programs; (3) Electric bad debt expense; and (4) the RAC for incurred MGP remediation expenditures. Over or under recovered balances with interest are to be returned or recovered through an annual filing. • Storm Damage and Other: Represents deferred costs, primarily comprised of storm costs incurred in the cleanup of major storms from 2010 through 2018, which are being amortized over five years. • Unamortized Loss on Reacquired Debt and Debt Expense: Represents losses on reacquired long-term debt and expenses associated with issuances of new debt, which are recovered through rates over the remaining life of the debt. • WNC: This represents the over or under recovery of gas margin which is filed annually with the BPU. The WNC requires PSE&G to calculate, at the end of each October-to-May period, the level by which margin revenues differed from what would have resulted if normal weather had occurred. Over recoveries are returned to customers in the next winter season while under recoveries (subject to an earnings cap) are recovered from customers in the next winter season. Significant 2018 regulatory orders received and currently pending rate filings with FERC and the BPU by PSE&G are as follows: • Electric and Gas Distribution Base Rate Filings —In October 2018, the BPU issued an Order approving the settlement of PSE&G’s distribution base rate proceeding with new rates effective November 1, 2018. The settlement resulted in a net reduction in overall annual revenues of approximately $13 million , comprised of a $212 million increase in base revenues, including recovery of deferred storm costs, offset by the return of tax benefits of approximately $225 million . The tax benefits include the 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. The Order provided for a $9.5 billion rate base, a 9.6% return on equity for PSE&G’s distribution business and a 54% equity component of its capitalization structure. In addition to the $13 million annual revenue reduction, the Order provided for a $28 million one-time refund to customers in November and December 2018 for taxes collected at the higher federal income tax rate for the January 1 to March 31, 2018 period. Previously, the BPU had approved a rate reduction effective April 1, 2018, to PSE&G’s then current electric and gas base rates of approximately $71 million and $43 million , respectively, on an annual basis, to reflect the lower federal income tax rate for the period April 1 and forward. As a result of the agreement to flow back tax repair-related accumulated deferred income taxes in the settlement, PSE&G has recognized a Regulatory Liability and a corresponding Regulatory Asset. • Transmission Formula Rate Filings —In October 2018, PSE&G made two FERC filings with respect to its Transmission Formula Rate. PSE&G filed its 2019 Annual Transmission Formula Rate Update with FERC requesting new rates for 2019 with an effective date of January 1, 2019. In addition, PSE&G filed a Section 205 filing that sought FERC approval to modify its existing Formula Rate template in order to refund approximately $114 million of transmission-related “unprotected excess deferred income tax benefits” in 2019. In December 2018, FERC approved PSE&G’s Section 205 filing, subject to the submission of a compliance filing which was submitted to FERC in January 2019. As a result, PSE&G filed a revised 2019 Annual Transmission Formula Rate Update to include the refund of the approved excess deferred income tax benefits. The revised 2019 Annual Transmission Formula Rate, as filed with FERC in January 2019, decreases overall annual transmission revenues by approximately $54 million , subject to true-up. In June 2018, PSE&G filed its 2017 true-up adjustment pertaining to its transmission formula rates in effect for 2017. This resulted in an adjustment of $27 million more than the 2017 originally filed revenues, the impact of which PSE&G had primarily recognized in its Consolidated Statement of Operations for the year ended December 31, 2017. • Gas System Modernization Program I (GSMP I) —In December 2018, the BPU approved recovery of PSE&G’s GSMP I capital investment recovery petition for an annual gas revenue requirement increase of $21 million effective January 1, 2019. • RAC —In January 2019, PSE&G updated its RAC 26 recovery request with the BPU seeking recovery of $73 million of net MGP costs from August 1, 2017 through July 31, 2018. This matter is pending. In October 2018, the BPU approved PSE&G’s filing with respect to its RAC 25 petition allowing recovery of $63 million effective November 1, 2018 related to MGP expenditures from August 1, 2016 through July 31, 2017. • GPRC —In October 2018, the BPU approved PSE&G’s 2017 GPRC cost recovery petition requesting recovery of approximately $58 million and $15 million in electric and gas revenues, respectively, on an annual basis. In June 2018, PSE&G filed its 2018 GPRC cost recovery petition requesting recovery of approximately $65 million and $6 million in electric and gas revenues, respectively, on an annual basis. • Energy Strong Program I (ES I) Recovery Filing —In August 2018, the BPU approved recovery of PSE&G’s ES I capital investment petition for an annual revenue requirement increase of $0.6 million and $0.1 million associated with electric and gas investment costs, respectively. This represents the final recovery of electric and gas ES I capital investment costs consistent with the BPU Order of Approval of the Energy Strong Program. In February 2018, the BPU approved recovery of an annual revenue requirement of $8 million associated with electric ES I capital investment costs placed in service from June 1, 2017 through November 30, 2017. • WNC —In October 2018, the BPU approved PSE&G’s 2017-2018 WNC petition on a provisional basis allowing a net recovery of $14 million to be collected over the 2018-2019 Winter Period with the new rate effective November 1, 2018. The $14 million net recovery is the result of $9 million of excess revenues from the colder than normal 2017-2018 Winter Period offset by $23 million of remaining prior Winter Period undercollection. In April 2018, the BPU gave final approval to PSE&G’s petition to collect $55 million in net deficiency gas revenues as a result of the warmer than normal 2016-2017 Winter Period, which resulted in a deficiency of $31 million , plus a carryover balance of $24 million from the 2015-2016 Winter Period. • SBC —In February 2018, the BPU approved PSE&G’s petition to increase electric rates by approximately $20 million on an annual basis and to decrease gas rates by approximately $0.8 million on an annual basis, in order to recover electric and gas costs incurred through May 31, 2017 under its Energy Efficiency and Renewable Energy and Social Programs. The new rates were effective April 1, 2018. • BGSS —In September 2018, the BPU provisionally approved PSE&G’s request to decrease its BGSS rates which will decrease annual BGSS revenues by $26 million . The BGSS rate decreased from approximately 37 cents to 35 cents per therm for residential gas customers effective October 1, 2018. In April 2018, the BPU approved the final BGSS rates which were effective October 1, 2017.
PSE&G [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory Assets and Liabilities	Regulatory Assets and Liabilities PSE&G prepares its financial statements in accordance with GAAP for regulated utilities as described in Note 1. Organization, Basis of Presentation and Significant Accounting Policies . PSE&G has deferred certain costs based on rate orders issued by the BPU or FERC or based on PSE&G’s experience with prior rate proceedings. Most of PSE&G’s Regulatory Assets and Liabilities as of December 31, 2018 are supported by written orders, either explicitly or implicitly through the BPU’s treatment of various cost items. These costs will be recovered and amortized over various future periods. Regulatory Assets and other investments and costs incurred under our various infrastructure filings and clause mechanisms are subject to prudence reviews and can be disallowed in the future by regulatory authorities. To the extent that collection of any infrastructure or clause mechanism revenue, Regulatory Assets or payments of Regulatory Liabilities is no longer probable, the amounts would be charged or credited to income. PSE&G had the following Regulatory Assets and Liabilities: As of December 31, 2018 2017 Millions Regulatory Assets Current New Jersey Clean Energy Program $ 143 $ 128 Electric Energy Costs—Basic Generation Service (BGS) 115 23 Storm Damage and Other 56 — Green Program Recovery Charges (GPRC) 34 8 Weather Normalization Clause (WNC) 2 40 Other 39 12 Total Current Regulatory Assets $ 389 $ 211 Noncurrent Pension and OPEB Costs $ 1,090 $ 1,488 Deferred Income Tax Regulatory Assets 896 282 Manufactured Gas Plant (MGP) Remediation Costs 321 358 Electric Transmission and Gas Cost of Removal 223 199 Storm Damage and Other 214 241 Remediation Adjustment Charge (RAC) (Other Societal Benefits Charge (SBC)) 175 172 Asset Retirement Obligation 166 162 GPRC 95 98 Unamortized Loss on Reacquired Debt and Debt Expense 49 55 Gas Costs—BGSS 31 30 Other 139 137 Total Noncurrent Regulatory Assets $ 3,399 $ 3,222 Total Regulatory Assets $ 3,788 $ 3,433 As of December 31, 2018 2017 Millions Regulatory Liabilities Current Deferred Income Tax Regulatory Liabilities $ 299 $ — Gas Costs —BGSS — 30 Gas Margin Adjustment Clause 8 12 Other 4 5 Total Current Regulatory Liabilities $ 311 $ 47 Noncurrent Deferred Income Tax Regulatory Liabilities $ 3,170 $ 2,868 Electric Distribution Cost of Removal 51 80 Total Noncurrent Regulatory Liabilities $ 3,221 $ 2,948 Total Regulatory Liabilities $ 3,532 $ 2,995 All Regulatory Assets and Liabilities are excluded from PSE&G’s rate base unless otherwise noted. The Regulatory Assets and Liabilities in the table above are defined as follows: • Asset Retirement Obligation: These costs represent the differences between rate-regulated cost of removal accounting and asset retirement accounting under GAAP. These costs will be recovered in future rates as assets are retired. • Deferred Income Tax Regulatory Assets: These amounts represent the portion of deferred income taxes that will be recovered through future rates, based upon established regulatory practices and orders from the BPU. • Deferred Income Tax Regulatory Liabilities: These amounts represent the future refunds to customers of PSE&G’s excess Accumulated Deferred Income Tax liabilities as a result of the reduction in the federal corporate income tax rate effective January 1, 2018 and the flow-back of tax repair-related accumulated deferred income taxes that PSE&G agreed to as part of the settlement of its 2018 distribution base rate proceeding. • Electric and Gas Cost of Removal: PSE&G accrues and collects in rates for the cost of removing, dismantling and disposing of its T&D assets upon retirement. The Regulatory Asset or Liability for non-legally required cost of removal represents the difference between amounts collected in rates and costs actually incurred. • Electric Energy Costs — BGS: These costs represent the over or under recovered amounts associated with BGS, as approved by the BPU. Pursuant to BPU requirements, PSE&G serves as the supplier of last resort for electric customers within its service territory that are not served by another supplier. Pricing for those services are set by the BPU as a pass-through, resulting in no margin for PSE&G’s operations. Over or under recovered balances with interest are returned or recovered through monthly filings. • Gas Costs — BGSS: These costs represent the over or under recovered amounts associated with BGSS, as approved by the BPU. Pursuant to BPU requirements, PSE&G serves as the supplier of last resort for gas customers within its service territory that are not served by another supplier. Pricing for those services are set by the BPU as a pass-through, resulting in no margin for PSE&G’s operations. Over or under collected balances are returned or recovered through an annual filing. Interest is accrued only on over recovered balances. • Gas Margin Adjustment Clause: This mechanism credits Firm delivery customers for net distribution margin revenue collected from Transportation Gas Service Non-Firm (TSG-NF) delivery customers. The balance represents the difference between the net margin collected from the TSG-NF Customers versus bill credits provided to Firm delivery customers. Over or under recovered balances with interest are returned or recovered through the subsequent annual filing. • GPRC: This amount represents costs of the over or under collected balances associated with various renewable energy and energy efficiency programs. PSE&G files annually with the BPU for recovery of amounts that include a return on and of its investment over the lives of the underlying investments and capital assets which range from five to ten years. Interest is accrued monthly on any over or under recovered balances. Components of the GPRC include: Carbon Abatement, Energy Efficiency Economic Stimulus Program (EEE), EEE Extension Program, EEE Extension II Program, the Demand Response Program, Solar Generation Investment Program (Solar 4 All ® ), Solar 4 All ® Extension, Solar 4 All ® Extension II, Solar Loan II Program, Solar Loan III Program and the Energy Efficiency 2017 Program. • MGP Remediation Costs: Represents the low end of the range for the remaining environmental investigation and remediation program cleanup costs for MGPs that are probable of recovery in future rates. Once these costs are incurred, they are recovered through the RAC in the SBC over a seven year period with interest. • New Jersey Clean Energy Program: The BPU approved future funding requirements for Energy Efficiency and Renewable Energy Programs through the first half of 2018. The BPU funding requirements are recovered through the SBC. • Pension and OPEB Costs: Pursuant to the adoption of accounting guidance for employers’ defined benefit pension and OPEB plans, PSE&G recorded the unrecognized costs for defined benefit pension and other OPEB plans on the balance sheet as a Regulatory Asset. These costs represent actuarial gains or losses and prior service costs which have not been expensed. These costs are amortized and recovered in future rates. • RAC (Other SBC): Costs incurred to clean up MGPs which are recovered over seven years with interest through an annual filing. • SBC: The SBC, as authorized by the BPU and the New Jersey Electric Discount and Energy Competition Act, includes costs related to PSE&G’s electric and gas business as follows: (1) the Universal Service Fund (USF); (2) Energy Efficiency and Renewable Energy Programs; (3) Electric bad debt expense; and (4) the RAC for incurred MGP remediation expenditures. Over or under recovered balances with interest are to be returned or recovered through an annual filing. • Storm Damage and Other: Represents deferred costs, primarily comprised of storm costs incurred in the cleanup of major storms from 2010 through 2018, which are being amortized over five years. • Unamortized Loss on Reacquired Debt and Debt Expense: Represents losses on reacquired long-term debt and expenses associated with issuances of new debt, which are recovered through rates over the remaining life of the debt. • WNC: This represents the over or under recovery of gas margin which is filed annually with the BPU. The WNC requires PSE&G to calculate, at the end of each October-to-May period, the level by which margin revenues differed from what would have resulted if normal weather had occurred. Over recoveries are returned to customers in the next winter season while under recoveries (subject to an earnings cap) are recovered from customers in the next winter season. Significant 2018 regulatory orders received and currently pending rate filings with FERC and the BPU by PSE&G are as follows: • Electric and Gas Distribution Base Rate Filings —In October 2018, the BPU issued an Order approving the settlement of PSE&G’s distribution base rate proceeding with new rates effective November 1, 2018. The settlement resulted in a net reduction in overall annual revenues of approximately $13 million , comprised of a $212 million increase in base revenues, including recovery of deferred storm costs, offset by the return of tax benefits of approximately $225 million . The tax benefits include the 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. The Order provided for a $9.5 billion rate base, a 9.6% return on equity for PSE&G’s distribution business and a 54% equity component of its capitalization structure. In addition to the $13 million annual revenue reduction, the Order provided for a $28 million one-time refund to customers in November and December 2018 for taxes collected at the higher federal income tax rate for the January 1 to March 31, 2018 period. Previously, the BPU had approved a rate reduction effective April 1, 2018, to PSE&G’s then current electric and gas base rates of approximately $71 million and $43 million , respectively, on an annual basis, to reflect the lower federal income tax rate for the period April 1 and forward. As a result of the agreement to flow back tax repair-related accumulated deferred income taxes in the settlement, PSE&G has recognized a Regulatory Liability and a corresponding Regulatory Asset. • Transmission Formula Rate Filings —In October 2018, PSE&G made two FERC filings with respect to its Transmission Formula Rate. PSE&G filed its 2019 Annual Transmission Formula Rate Update with FERC requesting new rates for 2019 with an effective date of January 1, 2019. In addition, PSE&G filed a Section 205 filing that sought FERC approval to modify its existing Formula Rate template in order to refund approximately $114 million of transmission-related “unprotected excess deferred income tax benefits” in 2019. In December 2018, FERC approved PSE&G’s Section 205 filing, subject to the submission of a compliance filing which was submitted to FERC in January 2019. As a result, PSE&G filed a revised 2019 Annual Transmission Formula Rate Update to include the refund of the approved excess deferred income tax benefits. The revised 2019 Annual Transmission Formula Rate, as filed with FERC in January 2019, decreases overall annual transmission revenues by approximately $54 million , subject to true-up. In June 2018, PSE&G filed its 2017 true-up adjustment pertaining to its transmission formula rates in effect for 2017. This resulted in an adjustment of $27 million more than the 2017 originally filed revenues, the impact of which PSE&G had primarily recognized in its Consolidated Statement of Operations for the year ended December 31, 2017. • Gas System Modernization Program I (GSMP I) —In December 2018, the BPU approved recovery of PSE&G’s GSMP I capital investment recovery petition for an annual gas revenue requirement increase of $21 million effective January 1, 2019. • RAC —In January 2019, PSE&G updated its RAC 26 recovery request with the BPU seeking recovery of $73 million of net MGP costs from August 1, 2017 through July 31, 2018. This matter is pending. In October 2018, the BPU approved PSE&G’s filing with respect to its RAC 25 petition allowing recovery of $63 million effective November 1, 2018 related to MGP expenditures from August 1, 2016 through July 31, 2017. • GPRC —In October 2018, the BPU approved PSE&G’s 2017 GPRC cost recovery petition requesting recovery of approximately $58 million and $15 million in electric and gas revenues, respectively, on an annual basis. In June 2018, PSE&G filed its 2018 GPRC cost recovery petition requesting recovery of approximately $65 million and $6 million in electric and gas revenues, respectively, on an annual basis. • Energy Strong Program I (ES I) Recovery Filing —In August 2018, the BPU approved recovery of PSE&G’s ES I capital investment petition for an annual revenue requirement increase of $0.6 million and $0.1 million associated with electric and gas investment costs, respectively. This represents the final recovery of electric and gas ES I capital investment costs consistent with the BPU Order of Approval of the Energy Strong Program. In February 2018, the BPU approved recovery of an annual revenue requirement of $8 million associated with electric ES I capital investment costs placed in service from June 1, 2017 through November 30, 2017. • WNC —In October 2018, the BPU approved PSE&G’s 2017-2018 WNC petition on a provisional basis allowing a net recovery of $14 million to be collected over the 2018-2019 Winter Period with the new rate effective November 1, 2018. The $14 million net recovery is the result of $9 million of excess revenues from the colder than normal 2017-2018 Winter Period offset by $23 million of remaining prior Winter Period undercollection. In April 2018, the BPU gave final approval to PSE&G’s petition to collect $55 million in net deficiency gas revenues as a result of the warmer than normal 2016-2017 Winter Period, which resulted in a deficiency of $31 million , plus a carryover balance of $24 million from the 2015-2016 Winter Period. • SBC —In February 2018, the BPU approved PSE&G’s petition to increase electric rates by approximately $20 million on an annual basis and to decrease gas rates by approximately $0.8 million on an annual basis, in order to recover electric and gas costs incurred through May 31, 2017 under its Energy Efficiency and Renewable Energy and Social Programs. The new rates were effective April 1, 2018. • BGSS —In September 2018, the BPU provisionally approved PSE&G’s request to decrease its BGSS rates which will decrease annual BGSS revenues by $26 million . The BGSS rate decreased from approximately 37 cents to 35 cents per therm for residential gas customers effective October 1, 2018. In April 2018, the BPU approved the final BGSS rates which were effective October 1, 2017.

Long-Term Investments

Long-Term Investments	12 Months Ended
	Dec. 31, 2018
Long-Term Investments [Line Items]
Long-Term Investments [Text Block]	Long-Term Investments Long-Term Investments as of December 31, 2018 and 2017 included the following: As of December 31, 2018 2017 Millions PSE&G Life Insurance and Supplemental Benefits $ 121 $ 130 Solar Loans 149 150 Power Partnerships and Corporate Joint Ventures (Equity Method Investments) (A) 86 87 Energy Holdings Lease Investments 540 565 Total Long-Term Investments $ 896 $ 932 (A) During the three years ended December 31, 2018 , 2017 and 2016 , dividends from these investments were $16 million , $18 million and $18 million , respectively. Leases Energy Holdings, through several of its indirect subsidiary companies, has investments in domestic energy and real estate assets subject primarily to leveraged lease accounting. A leveraged lease is typically comprised of an investment by an equity investor and debt provided by a third-party debt investor. The debt is recourse only to the assets subject to lease and is not included on PSEG’s Consolidated Balance Sheets. As an equity investor, Energy Holdings’ equity investments in the leases are comprised of the total expected lease receivables over the lease terms plus the estimated residual values at the end of the lease terms, reduced for any income not yet earned on the leases. This amount is included in Long-Term Investments on PSEG’s Consolidated Balance Sheets. The more rapid depreciation of the leased property for tax purposes creates tax cash flow that will be repaid to the taxing authority in later periods. As such, the liability for such taxes due is recorded in Deferred Income Taxes on PSEG’s Consolidated Balance Sheets. Due to liquidity issues facing NRG REMA, LLC (REMA) prior to its emergence from bankruptcy protection, economic challenges facing coal generation in PJM as discussed in Note 4. Early Plant Retirements , and based upon ongoing reviews of available alternatives as well as certain discussions with REMA management leading up to and in connection with REMA’s bankruptcy, Energy Holdings recorded pre-tax charges of $20 million , $77 million and $147 million in 2018 , 2017 and 2016 , respectively. Included in these charges were residual value impairments of $7 million and $137 million in 2017 and 2016 , respectively. Pre-tax charges were reflected in Operating Revenues in each year and are included in Gross Investment in Leases as of December 31, 2018 . In December 2018, REMA emerged from its in-court proceeding under Chapter 11 of the Bankruptcy Code. Upon emergence, PSEG received $31.5 million in cash in exchange for transferring the ownership interests in Keystone and Conemaugh to the debtholders of REMA and satisfaction of all other claims asserted against REMA, as well as certain amendments to the Shawville lease. The Shawville lease amendments, among other things, will allow REMA to express interest in a renewal on or after November 24, 2019. In addition, REMA has agreed to fund qualifying credit support up to $36 million . As a result of the restructuring, Energy Holdings recognized a pre-tax gain in Operating Revenues of approximately $12 million ( $9 million after tax). In addition, the remaining deferred tax liabilities related to these lease investments were reclassified to current tax liabilities. PSEG expects to pay approximately $120 million to taxing authorities in 2019 resulting from this restructuring activity. The following table shows Energy Holdings’ gross and net lease investment as of December 31, 2018 and 2017 . As of December 31, 2018 2017 Millions Lease Receivables (net of Non-Recourse Debt) $ 504 $ 546 Estimated Residual Value of Leased Assets 326 326 Total Investment in Rental Receivables 830 872 Unearned and Deferred Income (290 ) (307 ) Gross Investments in Leases 540 565 Deferred Tax Liabilities (354 ) (480 ) Net Investments in Leases $ 186 $ 85 In December 2017, new tax legislation was enacted (Tax Act), reducing the statutory U.S. corporate income tax rate from a maximum of 35% to 21% , effective January 1, 2018. PSEG is subject to ASC 740, which requires that the effect on deferred tax assets and liabilities of a change in tax rates be recognized in the period the tax rate was enacted. The impact of the reduced tax rate is the primary reason for the decrease in Deferred Tax Liabilities. For additional information, see Note 21. Income Taxes . The pre-tax income (loss) and income tax effects related to investments in leases, excluding gains and losses on sales and the impacts of the Tax Act, were as follows: Years Ended December 31, 2018 2017 2016 Millions Pre-Tax Income (Loss) from Leases $ 17 $ (69 ) $ (135 ) Income Tax Expense (Benefit) on Income from Leases $ 6 $ (26 ) $ (51 ) Equity Method Investments Power had the following equity method investments as of December 31, 2018 and 2017 : As of December 31, Name 2018 2017 Location % Owned Millions Power Keystone Fuels, LLC $ 9 $ 8 PA 23% Conemaugh Fuels, LLC 8 8 PA 23% Kalaeloa 69 71 HI 50% Total $ 86 $ 87
PSE&G [Member]
Long-Term Investments [Line Items]
Long-Term Investments [Text Block]	Long-Term Investments Long-Term Investments as of December 31, 2018 and 2017 included the following: As of December 31, 2018 2017 Millions PSE&G Life Insurance and Supplemental Benefits $ 121 $ 130 Solar Loans 149 150 Power Partnerships and Corporate Joint Ventures (Equity Method Investments) (A) 86 87 Energy Holdings Lease Investments 540 565 Total Long-Term Investments $ 896 $ 932 (A) During the three years ended December 31, 2018 , 2017 and 2016 , dividends from these investments were $16 million , $18 million and $18 million , respectively. Leases Energy Holdings, through several of its indirect subsidiary companies, has investments in domestic energy and real estate assets subject primarily to leveraged lease accounting. A leveraged lease is typically comprised of an investment by an equity investor and debt provided by a third-party debt investor. The debt is recourse only to the assets subject to lease and is not included on PSEG’s Consolidated Balance Sheets. As an equity investor, Energy Holdings’ equity investments in the leases are comprised of the total expected lease receivables over the lease terms plus the estimated residual values at the end of the lease terms, reduced for any income not yet earned on the leases. This amount is included in Long-Term Investments on PSEG’s Consolidated Balance Sheets. The more rapid depreciation of the leased property for tax purposes creates tax cash flow that will be repaid to the taxing authority in later periods. As such, the liability for such taxes due is recorded in Deferred Income Taxes on PSEG’s Consolidated Balance Sheets. Due to liquidity issues facing NRG REMA, LLC (REMA) prior to its emergence from bankruptcy protection, economic challenges facing coal generation in PJM as discussed in Note 4. Early Plant Retirements , and based upon ongoing reviews of available alternatives as well as certain discussions with REMA management leading up to and in connection with REMA’s bankruptcy, Energy Holdings recorded pre-tax charges of $20 million , $77 million and $147 million in 2018 , 2017 and 2016 , respectively. Included in these charges were residual value impairments of $7 million and $137 million in 2017 and 2016 , respectively. Pre-tax charges were reflected in Operating Revenues in each year and are included in Gross Investment in Leases as of December 31, 2018 . In December 2018, REMA emerged from its in-court proceeding under Chapter 11 of the Bankruptcy Code. Upon emergence, PSEG received $31.5 million in cash in exchange for transferring the ownership interests in Keystone and Conemaugh to the debtholders of REMA and satisfaction of all other claims asserted against REMA, as well as certain amendments to the Shawville lease. The Shawville lease amendments, among other things, will allow REMA to express interest in a renewal on or after November 24, 2019. In addition, REMA has agreed to fund qualifying credit support up to $36 million . As a result of the restructuring, Energy Holdings recognized a pre-tax gain in Operating Revenues of approximately $12 million ( $9 million after tax). In addition, the remaining deferred tax liabilities related to these lease investments were reclassified to current tax liabilities. PSEG expects to pay approximately $120 million to taxing authorities in 2019 resulting from this restructuring activity. The following table shows Energy Holdings’ gross and net lease investment as of December 31, 2018 and 2017 . As of December 31, 2018 2017 Millions Lease Receivables (net of Non-Recourse Debt) $ 504 $ 546 Estimated Residual Value of Leased Assets 326 326 Total Investment in Rental Receivables 830 872 Unearned and Deferred Income (290 ) (307 ) Gross Investments in Leases 540 565 Deferred Tax Liabilities (354 ) (480 ) Net Investments in Leases $ 186 $ 85 In December 2017, new tax legislation was enacted (Tax Act), reducing the statutory U.S. corporate income tax rate from a maximum of 35% to 21% , effective January 1, 2018. PSEG is subject to ASC 740, which requires that the effect on deferred tax assets and liabilities of a change in tax rates be recognized in the period the tax rate was enacted. The impact of the reduced tax rate is the primary reason for the decrease in Deferred Tax Liabilities. For additional information, see Note 21. Income Taxes . The pre-tax income (loss) and income tax effects related to investments in leases, excluding gains and losses on sales and the impacts of the Tax Act, were as follows: Years Ended December 31, 2018 2017 2016 Millions Pre-Tax Income (Loss) from Leases $ 17 $ (69 ) $ (135 ) Income Tax Expense (Benefit) on Income from Leases $ 6 $ (26 ) $ (51 ) Equity Method Investments Power had the following equity method investments as of December 31, 2018 and 2017 : As of December 31, Name 2018 2017 Location % Owned Millions Power Keystone Fuels, LLC $ 9 $ 8 PA 23% Conemaugh Fuels, LLC 8 8 PA 23% Kalaeloa 69 71 HI 50% Total $ 86 $ 87
Power [Member]
Long-Term Investments [Line Items]
Long-Term Investments [Text Block]	Long-Term Investments Long-Term Investments as of December 31, 2018 and 2017 included the following: As of December 31, 2018 2017 Millions PSE&G Life Insurance and Supplemental Benefits $ 121 $ 130 Solar Loans 149 150 Power Partnerships and Corporate Joint Ventures (Equity Method Investments) (A) 86 87 Energy Holdings Lease Investments 540 565 Total Long-Term Investments $ 896 $ 932 (A) During the three years ended December 31, 2018 , 2017 and 2016 , dividends from these investments were $16 million , $18 million and $18 million , respectively. Leases Energy Holdings, through several of its indirect subsidiary companies, has investments in domestic energy and real estate assets subject primarily to leveraged lease accounting. A leveraged lease is typically comprised of an investment by an equity investor and debt provided by a third-party debt investor. The debt is recourse only to the assets subject to lease and is not included on PSEG’s Consolidated Balance Sheets. As an equity investor, Energy Holdings’ equity investments in the leases are comprised of the total expected lease receivables over the lease terms plus the estimated residual values at the end of the lease terms, reduced for any income not yet earned on the leases. This amount is included in Long-Term Investments on PSEG’s Consolidated Balance Sheets. The more rapid depreciation of the leased property for tax purposes creates tax cash flow that will be repaid to the taxing authority in later periods. As such, the liability for such taxes due is recorded in Deferred Income Taxes on PSEG’s Consolidated Balance Sheets. Due to liquidity issues facing NRG REMA, LLC (REMA) prior to its emergence from bankruptcy protection, economic challenges facing coal generation in PJM as discussed in Note 4. Early Plant Retirements , and based upon ongoing reviews of available alternatives as well as certain discussions with REMA management leading up to and in connection with REMA’s bankruptcy, Energy Holdings recorded pre-tax charges of $20 million , $77 million and $147 million in 2018 , 2017 and 2016 , respectively. Included in these charges were residual value impairments of $7 million and $137 million in 2017 and 2016 , respectively. Pre-tax charges were reflected in Operating Revenues in each year and are included in Gross Investment in Leases as of December 31, 2018 . In December 2018, REMA emerged from its in-court proceeding under Chapter 11 of the Bankruptcy Code. Upon emergence, PSEG received $31.5 million in cash in exchange for transferring the ownership interests in Keystone and Conemaugh to the debtholders of REMA and satisfaction of all other claims asserted against REMA, as well as certain amendments to the Shawville lease. The Shawville lease amendments, among other things, will allow REMA to express interest in a renewal on or after November 24, 2019. In addition, REMA has agreed to fund qualifying credit support up to $36 million . As a result of the restructuring, Energy Holdings recognized a pre-tax gain in Operating Revenues of approximately $12 million ( $9 million after tax). In addition, the remaining deferred tax liabilities related to these lease investments were reclassified to current tax liabilities. PSEG expects to pay approximately $120 million to taxing authorities in 2019 resulting from this restructuring activity. The following table shows Energy Holdings’ gross and net lease investment as of December 31, 2018 and 2017 . As of December 31, 2018 2017 Millions Lease Receivables (net of Non-Recourse Debt) $ 504 $ 546 Estimated Residual Value of Leased Assets 326 326 Total Investment in Rental Receivables 830 872 Unearned and Deferred Income (290 ) (307 ) Gross Investments in Leases 540 565 Deferred Tax Liabilities (354 ) (480 ) Net Investments in Leases $ 186 $ 85 In December 2017, new tax legislation was enacted (Tax Act), reducing the statutory U.S. corporate income tax rate from a maximum of 35% to 21% , effective January 1, 2018. PSEG is subject to ASC 740, which requires that the effect on deferred tax assets and liabilities of a change in tax rates be recognized in the period the tax rate was enacted. The impact of the reduced tax rate is the primary reason for the decrease in Deferred Tax Liabilities. For additional information, see Note 21. Income Taxes . The pre-tax income (loss) and income tax effects related to investments in leases, excluding gains and losses on sales and the impacts of the Tax Act, were as follows: Years Ended December 31, 2018 2017 2016 Millions Pre-Tax Income (Loss) from Leases $ 17 $ (69 ) $ (135 ) Income Tax Expense (Benefit) on Income from Leases $ 6 $ (26 ) $ (51 ) Equity Method Investments Power had the following equity method investments as of December 31, 2018 and 2017 : As of December 31, Name 2018 2017 Location % Owned Millions Power Keystone Fuels, LLC $ 9 $ 8 PA 23% Conemaugh Fuels, LLC 8 8 PA 23% Kalaeloa 69 71 HI 50% Total $ 86 $ 87

Financing Receivables

Financing Receivables	12 Months Ended
	Dec. 31, 2018
Financing Receivable, Recorded Investment [Line Items]
Financing Receivables	Financing Receivables PSE&G PSE&G sponsors a solar loan program designed to help finance the installation of solar power systems throughout its electric service area. Interest income on the loans is recorded on an accrual basis. The loans are generally paid back with solar renewable energy certificates (SRECs) generated from the installed solar electric system. In the event of a loan default, the basis of the solar loan would be recovered through a regulatory recovery mechanism. None of the solar loans are impaired; however, in the event a loan becomes impaired, the basis of the loan would be recovered through a regulatory recovery mechanism. A substantial portion of these amounts are noncurrent and reported in Long-Term Investments on PSEG’s and PSE&G’s Consolidated Balance Sheets. The following table reflects the outstanding loans by class of customer, none of which would be considered “non-performing.” Outstanding Loans by Class of Customer As of December 31, Consumer Loans 2018 2017 Millions Commercial/Industrial $ 164 $ 158 Residential 9 10 Total $ 173 $ 168 Current Portion (included in Other Current Assets) (24 ) (18 ) Noncurrent Portion (included in Long-Term Investments) $ 149 $ 150 Energy Holdings Energy Holdings had a net investment in domestic energy and real estate assets subject to leveraged lease accounting of $186 million as of December 31, 2018 and $85 million as of December 31, 2017 (See Note 8. Long-Term Investments ). The corresponding receivables associated with the lease portfolio are reflected as follows, net of non-recourse debt. The ratings in the table represent the ratings of the entities providing payment assurance to Energy Holdings. Lease Receivables, Net of Non-Recourse Debt Counterparties’ Credit Rating Standard & Poor’s (S&P) as of December 31, 2018 As of December 31, 2018 Millions AA $ 14 BBB+ — BBB- 316 BB 133 NR 41 Total $ 504 The “ BB ” and the “ NR ” ratings in the preceding table represent lease receivables related to coal and gas-fired assets in Illinois and Pennsylvania, respectively. As of December 31, 2018 , the gross investment in the leases of such assets, net of non-recourse debt, was $296 million ( $10 million , net of deferred taxes). A more detailed description of such assets under lease follows: Asset Location Gross Investment % Owned Total MW Fuel Type Counterparties’ S&P Credit Ratings Counterparty Millions Powerton Station Units 5 and 6 IL $ 133 64 % 1,538 Coal BB NRG Energy, Inc. Joliet Station Units 7 and 8 IL $ 85 64 % 1,036 Gas BB NRG Energy, Inc. Shawville Station Units 1, 2, 3 and 4 PA $ 78 100 % 596 Gas NR REMA (A) (A) REMA emerged from Chapter 11 of the U.S. Bankruptcy Code in December 2018. For additional information, see Note 8. Long-Term Investments . The credit exposure for lessors is partially mitigated through various credit enhancement mechanisms within the lease structures. These credit enhancement features vary from lease to lease. Upon the occurrence of certain defaults, indirect subsidiary companies of Energy Holdings would exercise their rights and seek recovery of their investment, potentially including stepping into the lease directly to protect their investments. While these actions could ultimately protect or mitigate the loss of value, they could require the use of significant capital and trigger certain material tax obligations which could, for certain leases, wholly or partially be mitigated by tax indemnification claims against the counterparty. A bankruptcy of a lessee would likely delay and potentially limit any efforts on the part of the lessors to assert their rights upon default and could delay the monetization of claims. Additional factors that may impact future lease cash flows include, but are not limited to, new environmental legislation and regulation regarding air quality, water and other discharges in the process of generating electricity, market prices for fuel, electricity and capacity, overall financial condition of lease counterparties and their affiliates and the quality and condition of assets under lease.
PSE&G [Member]
Financing Receivable, Recorded Investment [Line Items]
Financing Receivables	Financing Receivables PSE&G PSE&G sponsors a solar loan program designed to help finance the installation of solar power systems throughout its electric service area. Interest income on the loans is recorded on an accrual basis. The loans are generally paid back with solar renewable energy certificates (SRECs) generated from the installed solar electric system. In the event of a loan default, the basis of the solar loan would be recovered through a regulatory recovery mechanism. None of the solar loans are impaired; however, in the event a loan becomes impaired, the basis of the loan would be recovered through a regulatory recovery mechanism. A substantial portion of these amounts are noncurrent and reported in Long-Term Investments on PSEG’s and PSE&G’s Consolidated Balance Sheets. The following table reflects the outstanding loans by class of customer, none of which would be considered “non-performing.” Outstanding Loans by Class of Customer As of December 31, Consumer Loans 2018 2017 Millions Commercial/Industrial $ 164 $ 158 Residential 9 10 Total $ 173 $ 168 Current Portion (included in Other Current Assets) (24 ) (18 ) Noncurrent Portion (included in Long-Term Investments) $ 149 $ 150 Energy Holdings Energy Holdings had a net investment in domestic energy and real estate assets subject to leveraged lease accounting of $186 million as of December 31, 2018 and $85 million as of December 31, 2017 (See Note 8. Long-Term Investments ). The corresponding receivables associated with the lease portfolio are reflected as follows, net of non-recourse debt. The ratings in the table represent the ratings of the entities providing payment assurance to Energy Holdings. Lease Receivables, Net of Non-Recourse Debt Counterparties’ Credit Rating Standard & Poor’s (S&P) as of December 31, 2018 As of December 31, 2018 Millions AA $ 14 BBB+ — BBB- 316 BB 133 NR 41 Total $ 504 The “ BB ” and the “ NR ” ratings in the preceding table represent lease receivables related to coal and gas-fired assets in Illinois and Pennsylvania, respectively. As of December 31, 2018 , the gross investment in the leases of such assets, net of non-recourse debt, was $296 million ( $10 million , net of deferred taxes). A more detailed description of such assets under lease follows: Asset Location Gross Investment % Owned Total MW Fuel Type Counterparties’ S&P Credit Ratings Counterparty Millions Powerton Station Units 5 and 6 IL $ 133 64 % 1,538 Coal BB NRG Energy, Inc. Joliet Station Units 7 and 8 IL $ 85 64 % 1,036 Gas BB NRG Energy, Inc. Shawville Station Units 1, 2, 3 and 4 PA $ 78 100 % 596 Gas NR REMA (A) (A) REMA emerged from Chapter 11 of the U.S. Bankruptcy Code in December 2018. For additional information, see Note 8. Long-Term Investments . The credit exposure for lessors is partially mitigated through various credit enhancement mechanisms within the lease structures. These credit enhancement features vary from lease to lease. Upon the occurrence of certain defaults, indirect subsidiary companies of Energy Holdings would exercise their rights and seek recovery of their investment, potentially including stepping into the lease directly to protect their investments. While these actions could ultimately protect or mitigate the loss of value, they could require the use of significant capital and trigger certain material tax obligations which could, for certain leases, wholly or partially be mitigated by tax indemnification claims against the counterparty. A bankruptcy of a lessee would likely delay and potentially limit any efforts on the part of the lessors to assert their rights upon default and could delay the monetization of claims. Additional factors that may impact future lease cash flows include, but are not limited to, new environmental legislation and regulation regarding air quality, water and other discharges in the process of generating electricity, market prices for fuel, electricity and capacity, overall financial condition of lease counterparties and their affiliates and the quality and condition of assets under lease.

Trust Investments

Trust Investments	12 Months Ended
	Dec. 31, 2018
Schedule of Trust Investments [Line Items]
Trust Investments [Text Block]	NDT Fund In accordance with NRC regulations, entities owning an interest in nuclear generating facilities are required to determine the costs and funding methods necessary to decommission such facilities upon termination of operation. As a general practice, each nuclear owner places funds in independent external trust accounts it maintains to provide for decommissioning. Power is required to file periodic reports with the NRC demonstrating that its NDT Fund meets the formula-based minimum NRC funding requirements. Power maintains an external master NDT to fund its share of decommissioning for its five nuclear facilities upon their respective termination of operation. The trust contains two separate funds: a qualified fund and a non-qualified fund. Section 468A of the Internal Revenue Code limits the amount of money that can be contributed into a qualified fund. Power’s share of decommissioning costs related to its five nuclear units was estimated to be between $2.8 billion and $3.0 billion , including contingencies. The liability for decommissioning recorded on a discounted basis as of December 31, 2018 was approximately $708 million and is included in the Asset Retirement Obligation. The funds are managed by third-party investment managers who operate under investment guidelines developed by Power. The following tables show the fair values and gross unrealized gains and losses for the securities held in the NDT Fund. As of December 31, 2018 Cost Gross Unrealized Gains Gross Unrealized Losses Fair Value Millions Equity Securities Domestic $ 447 $ 153 $ (29 ) $ 571 International 323 36 (30 ) 329 Total Equity Securities 770 189 (59 ) 900 Available-for Sale Debt Securities Government 498 2 (9 ) 491 Corporate 501 1 (15 ) 487 Total Available-for-Sale Debt Securities 999 3 (24 ) 978 Total NDT Fund Investments $ 1,769 $ 192 $ (83 ) $ 1,878 As of December 31, 2017 Cost Gross Unrealized Gains Gross Unrealized Losses Fair Value Millions Equity Securities Domestic $ 497 $ 245 $ (2 ) $ 740 International 311 99 — (3 ) 407 Total Equity Securities 808 344 (5 ) 1,147 Available-for Sale Debt Securities Government 586 2 (4 ) 584 Corporate 400 4 (2 ) 402 Total Available-for-Sale Debt Securities 986 6 (6 ) 986 Total NDT Fund Investments $ 1,794 $ 350 $ (11 ) $ 2,133 Net unrealized gains (losses) on debt securities of $(12) million (after-tax) were included in Accumulated Other Comprehensive Loss on PSEG’s and Power’s Consolidated Balance Sheets as of December 31, 2018 . The portion of net unrealized gains (losses) recognized during 2018 related to equity securities still held at the end of December 31, 2018 was $(127) million . The amounts in the preceding tables do not include receivables and payables for NDT Fund transactions which have not settled at the end of each period. Such amounts are included in Accounts Receivable and Accounts Payable on the Consolidated Balance Sheets as shown in the following table. As of December 31, 2018 As of December 31, 2017 Millions Accounts Receivable $ 17 $ 24 Accounts Payable $ 5 $ 74 The following table shows the value of securities in the NDT Fund that have been in an unrealized loss position for less than and greater than 12 months. As of December 31, 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 Equity Securities (A) Domestic $ 147 $ (26 ) $ 5 $ (3 ) $ 40 $ (2 ) $ — $ — International 131 (28 ) 5 (2 ) 29 (3 ) 2 — Total Equity Securities 278 (54 ) 10 (5 ) 69 (5 ) 2 — Available-for-Sale Debt Securities Government (B) 51 — 317 (9 ) 343 (2 ) 91 (2 ) Corporate (C) 150 (5 ) 222 (10 ) 191 (1 ) 27 (1 ) Total Available-for-Sale Debt Securities 201 (5 ) 539 (19 ) 534 (3 ) 118 (3 ) NDT Trust Investments $ 479 $ (59 ) $ 549 $ (24 ) $ 603 $ (8 ) $ 120 $ (3 ) (A) Equity Securities—Investments in marketable equity securities within the NDT Fund are primarily in common stocks within a broad range of industries and sectors. Effective January 1, 2018, unrealized gains and losses on these securities are recorded in Net Income. (B) Debt Securities (Government)—Unrealized gains and losses on these securities are recorded in Accumulated Other Comprehensive Income (Loss). The unrealized losses on Power’s NDT investments in U.S. Treasury obligations and Federal Agency mortgage-backed securities were caused by interest rate changes. These investments are guaranteed by the U.S. government or an agency of the U.S. government. Power also has investments in municipal bonds that are primarily in investment grade securities. It is not expected that these securities will settle for less than their amortized cost. Since Power does not intend to sell these securities nor will it be more-likely-than-not required to sell, Power does not consider these debt securities to be other-than-temporarily impaired as of December 31, 2018 . (C) Debt Securities (Corporate)—Unrealized gains and losses on these securities are recorded in Accumulated Other Comprehensive Income (Loss). Power’s investments in corporate bonds are primarily in investment grade securities. It is not expected that these securities would settle for less than their amortized cost. Since Power does not intend to sell these securities nor will it be more-likely-than-not required to sell, Power does not consider these debt securities to be other-than-temporarily impaired as of December 31, 2018 . The proceeds from the sales of and the net gains (losses) on securities in the NDT Fund were: Years Ended December 31, 2018 2017 2016 Millions Proceeds from Sales (A) $ 1,398 $ 2,137 $ 711 Net Realized Gains (Losses): Gross Realized Gains $ 121 $ 157 $ 53 Gross Realized Losses (51 ) (23 ) (32 ) Net Realized Gains (Losses) on NDT Fund (B) $ 70 $ 134 $ 21 Unrealized Gains (Losses) on Equity Securities in NDT Fund (C) (209 ) N/A N/A Other-Than-Temporary-Impairments (OTTI) — (12 ) (28 ) Net Gains (Losses) on NDT Fund Investments $ (139 ) $ 122 $ (7 ) (A) Includes activity in accounts related to the liquidation of funds being transitioned to new managers. (B) The cost of these securities was determined on the basis of specific identification. (C) Effective January 1, 2018, unrealized gains (losses) on equity securities are recorded in Net Income instead of Other Comprehensive Income (Loss). The NDT Fund debt securities held as of December 31, 2018 had the following maturities: Time Frame Fair Value Millions Less than one year $ 13 1 - 5 years 254 6 - 10 years 211 11 - 15 years 40 16 - 20 years 77 Over 20 years 383 Total NDT Available-for-Sale Debt Securities $ 978 Power periodically assesses individual debt securities whose fair value is less than amortized cost to determine whether the investments are considered to be other-than-temporarily impaired. For these securities, management considers its intent to sell or requirement to sell a security prior to expected recovery. In those cases where a sale is expected, any impairment would be recorded through earnings. For fixed income securities where there is no intent to sell or likely requirement to sell, management evaluates whether credit loss is a component of the impairment. If so, that portion is recorded through earnings while the noncredit loss component is recorded through Accumulated Other Comprehensive Income (Loss). Any subsequent recoveries in the value of these securities would be recognized in Accumulated Other Comprehensive Income (Loss) unless the securities are sold, in which case, any gain would be recognized in income. The assessment of fair market value compared to cost is applied on a weighted average basis taking into account various purchase dates and initial cost of the securities. Rabbi Trust PSEG maintains certain unfunded nonqualified benefit plans to provide supplemental retirement and deferred compensation benefits to certain key employees. Certain assets related to these plans have been set aside in a grantor trust commonly known as a “Rabbi Trust.” The following tables show the fair values, gross unrealized gains and losses and amortized cost basis for the securities held in the Rabbi Trust. As of December 31, 2018 Cost Gross Unrealized Gains Gross Unrealized Losses Fair Value Millions Equity Securities Domestic $ 22 $ 1 $ — $ 23 International — — — — Total Equity Securities 22 1 — 23 Available-for-Sale Debt Securities Government 110 1 (2 ) 109 Corporate 96 — (4 ) 92 Total Available-for-Sale Debt Securities 206 1 (6 ) 201 Total Rabbi Trust Investments $ 228 $ 2 $ (6 ) $ 224 As of December 31, 2017 Cost Gross Unrealized Gains Gross Unrealized Losses Fair Value Millions Equity Securities Domestic $ 24 $ 3 $ — $ 27 International — — — — Total Equity Securities 24 3 — 27 Available-for-Sale Debt Securities Government 85 1 (1 ) 85 Corporate 118 2 (1 ) 119 Total Available-for-Sale Debt Securities 203 3 (2 ) 204 Total Rabbi Trust Investments $ 227 $ 6 $ (2 ) $ 231 Net unrealized gains (losses) on debt securities of $(4) million (after-tax) were included in Accumulated Other Comprehensive Loss on PSEG’s Consolidated Balance Sheet as of December 31, 2018 . The portion of net unrealized gains (losses) recognized during 2018 related to equity securities still held at the end of December 31, 2018 was $(2) million . The amounts in the preceding tables do not include receivables and payables for Rabbi Trust Fund transactions which have not settled at the end of each period. Such amounts are included in Accounts Receivable and Accounts Payable on the Consolidated Balance Sheets as shown in the following table. As of December 31, 2018 As of December 31, 2017 Millions Accounts Receivable $ 2 $ 2 Accounts Payable $ — $ 1 The following table shows the value of securities in the Rabbi Trust Fund that have been in an unrealized loss position for less than and greater than 12 months: As of December 31, 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) $ 18 $ — $ 59 $ (2 ) $ 28 $ — $ 25 $ (1 ) Corporate (B) 50 (3 ) 29 (1 ) 39 (1 ) 9 — Total Available-for-Sale Debt Securities 68 (3 ) 88 (3 ) 67 (1 ) 34 (1 ) Rabbi Trust Investments $ 68 $ (3 ) $ 88 $ (3 ) $ 67 $ (1 ) $ 34 $ (1 ) (A) Debt Securities (Government)—Unrealized gains and losses on these securities are recorded in Accumulated Other Comprehensive Income (Loss). The unrealized losses on PSEG’s Rabbi Trust investments in U.S. Treasury obligations and Federal Agency mortgage-backed securities were caused by interest rate changes. These investments are guaranteed by the U.S. government or an agency of the U.S. government. PSEG also has investments in municipal bonds that are primarily in investment grade securities. It is not expected that these securities will settle for less than their amortized cost. Since PSEG does not intend to sell these securities nor will it be more-likely-than-not required to sell, PSEG does not consider these debt securities to be other-than-temporarily impaired as of December 31, 2018 . (B) Debt Securities (Corporate)—Unrealized gains and losses on these securities are recorded in Accumulated Other Comprehensive Income (Loss). PSEG’s investments in corporate bonds are primarily in investment grade securities. It is not expected that these securities would settle for less than their amortized cost. Since PSEG does not intend to sell these securities nor will it be more-likely-than-not required to sell, PSEG does not consider these debt securities to be other-than-temporarily impaired as of December 31, 2018 . The proceeds from the sales of and the net gains (losses) on securities in the Rabbi Trust Fund were: Years Ended December 31, 2018 2017 2016 Millions Proceeds from Rabbi Trust Sales (A) $ 103 $ 182 $ 113 Net Realized Gains (Losses): Gross Realized Gains $ 2 $ 17 $ 6 Gross Realized Losses (4 ) (5 ) (5 ) Net Realized Gains (Losses) on Rabbi Trust (B) (2 ) 12 1 Unrealized Gains (Losses) on Equity Securities in Rabbi Trust (C) (2 ) N/A N/A Net Gains (Losses) on Rabbi Trust Investments $ (4 ) $ 12 $ 1 (A) Includes activity in accounts related to the liquidation of funds being transitioned to new managers. (B) The cost of these securities was determined on the basis of specific identification. (C) Effective January 1, 2018, unrealized gains (losses) on equity securities are recorded in Net Income instead of Other Comprehensive Income (Loss). The Rabbi Trust debt securities held as of December 31, 2018 had the following maturities: Time Frame Fair Value Millions Less than one year $ 1 1 - 5 years 35 6 - 10 years 27 11 - 15 years 8 16 - 20 years 21 Over 20 years 109 Total Rabbi Trust Available-for-Sale Debt Securities $ 201 PSEG periodically assesses individual debt securities whose fair value is less than amortized cost to determine whether the investments are considered to be other-than-temporarily impaired. For these securities, management considers its intent to sell or requirement to sell a security prior to expected recovery. In those cases where a sale is expected, any impairment would be recorded through earnings. For fixed income securities where there is no intent to sell or likely requirement to sell, management evaluates whether credit loss is a component of the impairment. If so, that portion is recorded through earnings while the noncredit loss component is recorded through Accumulated Other Comprehensive Income (Loss). The assessment of fair market value compared to cost is applied on a weighted average basis taking into account various purchase dates and initial cost of the securities. The fair value of the Rabbi Trust related to PSEG, PSE&G and Power are detailed as follows: As of December 31, As of December 31, 2018 2017 Millions PSE&G $ 45 $ 46 Power 56 57 Other 123 128 Total Rabbi Trust Investments $ 224 $ 231
PSE&G [Member]
Schedule of Trust Investments [Line Items]
Trust Investments [Text Block]	NDT Fund In accordance with NRC regulations, entities owning an interest in nuclear generating facilities are required to determine the costs and funding methods necessary to decommission such facilities upon termination of operation. As a general practice, each nuclear owner places funds in independent external trust accounts it maintains to provide for decommissioning. Power is required to file periodic reports with the NRC demonstrating that its NDT Fund meets the formula-based minimum NRC funding requirements. Power maintains an external master NDT to fund its share of decommissioning for its five nuclear facilities upon their respective termination of operation. The trust contains two separate funds: a qualified fund and a non-qualified fund. Section 468A of the Internal Revenue Code limits the amount of money that can be contributed into a qualified fund. Power’s share of decommissioning costs related to its five nuclear units was estimated to be between $2.8 billion and $3.0 billion , including contingencies. The liability for decommissioning recorded on a discounted basis as of December 31, 2018 was approximately $708 million and is included in the Asset Retirement Obligation. The funds are managed by third-party investment managers who operate under investment guidelines developed by Power. The following tables show the fair values and gross unrealized gains and losses for the securities held in the NDT Fund. As of December 31, 2018 Cost Gross Unrealized Gains Gross Unrealized Losses Fair Value Millions Equity Securities Domestic $ 447 $ 153 $ (29 ) $ 571 International 323 36 (30 ) 329 Total Equity Securities 770 189 (59 ) 900 Available-for Sale Debt Securities Government 498 2 (9 ) 491 Corporate 501 1 (15 ) 487 Total Available-for-Sale Debt Securities 999 3 (24 ) 978 Total NDT Fund Investments $ 1,769 $ 192 $ (83 ) $ 1,878 As of December 31, 2017 Cost Gross Unrealized Gains Gross Unrealized Losses Fair Value Millions Equity Securities Domestic $ 497 $ 245 $ (2 ) $ 740 International 311 99 — (3 ) 407 Total Equity Securities 808 344 (5 ) 1,147 Available-for Sale Debt Securities Government 586 2 (4 ) 584 Corporate 400 4 (2 ) 402 Total Available-for-Sale Debt Securities 986 6 (6 ) 986 Total NDT Fund Investments $ 1,794 $ 350 $ (11 ) $ 2,133 Net unrealized gains (losses) on debt securities of $(12) million (after-tax) were included in Accumulated Other Comprehensive Loss on PSEG’s and Power’s Consolidated Balance Sheets as of December 31, 2018 . The portion of net unrealized gains (losses) recognized during 2018 related to equity securities still held at the end of December 31, 2018 was $(127) million . The amounts in the preceding tables do not include receivables and payables for NDT Fund transactions which have not settled at the end of each period. Such amounts are included in Accounts Receivable and Accounts Payable on the Consolidated Balance Sheets as shown in the following table. As of December 31, 2018 As of December 31, 2017 Millions Accounts Receivable $ 17 $ 24 Accounts Payable $ 5 $ 74 The following table shows the value of securities in the NDT Fund that have been in an unrealized loss position for less than and greater than 12 months. As of December 31, 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 Equity Securities (A) Domestic $ 147 $ (26 ) $ 5 $ (3 ) $ 40 $ (2 ) $ — $ — International 131 (28 ) 5 (2 ) 29 (3 ) 2 — Total Equity Securities 278 (54 ) 10 (5 ) 69 (5 ) 2 — Available-for-Sale Debt Securities Government (B) 51 — 317 (9 ) 343 (2 ) 91 (2 ) Corporate (C) 150 (5 ) 222 (10 ) 191 (1 ) 27 (1 ) Total Available-for-Sale Debt Securities 201 (5 ) 539 (19 ) 534 (3 ) 118 (3 ) NDT Trust Investments $ 479 $ (59 ) $ 549 $ (24 ) $ 603 $ (8 ) $ 120 $ (3 ) (A) Equity Securities—Investments in marketable equity securities within the NDT Fund are primarily in common stocks within a broad range of industries and sectors. Effective January 1, 2018, unrealized gains and losses on these securities are recorded in Net Income. (B) Debt Securities (Government)—Unrealized gains and losses on these securities are recorded in Accumulated Other Comprehensive Income (Loss). The unrealized losses on Power’s NDT investments in U.S. Treasury obligations and Federal Agency mortgage-backed securities were caused by interest rate changes. These investments are guaranteed by the U.S. government or an agency of the U.S. government. Power also has investments in municipal bonds that are primarily in investment grade securities. It is not expected that these securities will settle for less than their amortized cost. Since Power does not intend to sell these securities nor will it be more-likely-than-not required to sell, Power does not consider these debt securities to be other-than-temporarily impaired as of December 31, 2018 . (C) Debt Securities (Corporate)—Unrealized gains and losses on these securities are recorded in Accumulated Other Comprehensive Income (Loss). Power’s investments in corporate bonds are primarily in investment grade securities. It is not expected that these securities would settle for less than their amortized cost. Since Power does not intend to sell these securities nor will it be more-likely-than-not required to sell, Power does not consider these debt securities to be other-than-temporarily impaired as of December 31, 2018 . The proceeds from the sales of and the net gains (losses) on securities in the NDT Fund were: Years Ended December 31, 2018 2017 2016 Millions Proceeds from Sales (A) $ 1,398 $ 2,137 $ 711 Net Realized Gains (Losses): Gross Realized Gains $ 121 $ 157 $ 53 Gross Realized Losses (51 ) (23 ) (32 ) Net Realized Gains (Losses) on NDT Fund (B) $ 70 $ 134 $ 21 Unrealized Gains (Losses) on Equity Securities in NDT Fund (C) (209 ) N/A N/A Other-Than-Temporary-Impairments (OTTI) — (12 ) (28 ) Net Gains (Losses) on NDT Fund Investments $ (139 ) $ 122 $ (7 ) (A) Includes activity in accounts related to the liquidation of funds being transitioned to new managers. (B) The cost of these securities was determined on the basis of specific identification. (C) Effective January 1, 2018, unrealized gains (losses) on equity securities are recorded in Net Income instead of Other Comprehensive Income (Loss). The NDT Fund debt securities held as of December 31, 2018 had the following maturities: Time Frame Fair Value Millions Less than one year $ 13 1 - 5 years 254 6 - 10 years 211 11 - 15 years 40 16 - 20 years 77 Over 20 years 383 Total NDT Available-for-Sale Debt Securities $ 978 Power periodically assesses individual debt securities whose fair value is less than amortized cost to determine whether the investments are considered to be other-than-temporarily impaired. For these securities, management considers its intent to sell or requirement to sell a security prior to expected recovery. In those cases where a sale is expected, any impairment would be recorded through earnings. For fixed income securities where there is no intent to sell or likely requirement to sell, management evaluates whether credit loss is a component of the impairment. If so, that portion is recorded through earnings while the noncredit loss component is recorded through Accumulated Other Comprehensive Income (Loss). Any subsequent recoveries in the value of these securities would be recognized in Accumulated Other Comprehensive Income (Loss) unless the securities are sold, in which case, any gain would be recognized in income. The assessment of fair market value compared to cost is applied on a weighted average basis taking into account various purchase dates and initial cost of the securities. Rabbi Trust PSEG maintains certain unfunded nonqualified benefit plans to provide supplemental retirement and deferred compensation benefits to certain key employees. Certain assets related to these plans have been set aside in a grantor trust commonly known as a “Rabbi Trust.” The following tables show the fair values, gross unrealized gains and losses and amortized cost basis for the securities held in the Rabbi Trust. As of December 31, 2018 Cost Gross Unrealized Gains Gross Unrealized Losses Fair Value Millions Equity Securities Domestic $ 22 $ 1 $ — $ 23 International — — — — Total Equity Securities 22 1 — 23 Available-for-Sale Debt Securities Government 110 1 (2 ) 109 Corporate 96 — (4 ) 92 Total Available-for-Sale Debt Securities 206 1 (6 ) 201 Total Rabbi Trust Investments $ 228 $ 2 $ (6 ) $ 224 As of December 31, 2017 Cost Gross Unrealized Gains Gross Unrealized Losses Fair Value Millions Equity Securities Domestic $ 24 $ 3 $ — $ 27 International — — — — Total Equity Securities 24 3 — 27 Available-for-Sale Debt Securities Government 85 1 (1 ) 85 Corporate 118 2 (1 ) 119 Total Available-for-Sale Debt Securities 203 3 (2 ) 204 Total Rabbi Trust Investments $ 227 $ 6 $ (2 ) $ 231 Net unrealized gains (losses) on debt securities of $(4) million (after-tax) were included in Accumulated Other Comprehensive Loss on PSEG’s Consolidated Balance Sheet as of December 31, 2018 . The portion of net unrealized gains (losses) recognized during 2018 related to equity securities still held at the end of December 31, 2018 was $(2) million . The amounts in the preceding tables do not include receivables and payables for Rabbi Trust Fund transactions which have not settled at the end of each period. Such amounts are included in Accounts Receivable and Accounts Payable on the Consolidated Balance Sheets as shown in the following table. As of December 31, 2018 As of December 31, 2017 Millions Accounts Receivable $ 2 $ 2 Accounts Payable $ — $ 1 The following table shows the value of securities in the Rabbi Trust Fund that have been in an unrealized loss position for less than and greater than 12 months: As of December 31, 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) $ 18 $ — $ 59 $ (2 ) $ 28 $ — $ 25 $ (1 ) Corporate (B) 50 (3 ) 29 (1 ) 39 (1 ) 9 — Total Available-for-Sale Debt Securities 68 (3 ) 88 (3 ) 67 (1 ) 34 (1 ) Rabbi Trust Investments $ 68 $ (3 ) $ 88 $ (3 ) $ 67 $ (1 ) $ 34 $ (1 ) (A) Debt Securities (Government)—Unrealized gains and losses on these securities are recorded in Accumulated Other Comprehensive Income (Loss). The unrealized losses on PSEG’s Rabbi Trust investments in U.S. Treasury obligations and Federal Agency mortgage-backed securities were caused by interest rate changes. These investments are guaranteed by the U.S. government or an agency of the U.S. government. PSEG also has investments in municipal bonds that are primarily in investment grade securities. It is not expected that these securities will settle for less than their amortized cost. Since PSEG does not intend to sell these securities nor will it be more-likely-than-not required to sell, PSEG does not consider these debt securities to be other-than-temporarily impaired as of December 31, 2018 . (B) Debt Securities (Corporate)—Unrealized gains and losses on these securities are recorded in Accumulated Other Comprehensive Income (Loss). PSEG’s investments in corporate bonds are primarily in investment grade securities. It is not expected that these securities would settle for less than their amortized cost. Since PSEG does not intend to sell these securities nor will it be more-likely-than-not required to sell, PSEG does not consider these debt securities to be other-than-temporarily impaired as of December 31, 2018 . The proceeds from the sales of and the net gains (losses) on securities in the Rabbi Trust Fund were: Years Ended December 31, 2018 2017 2016 Millions Proceeds from Rabbi Trust Sales (A) $ 103 $ 182 $ 113 Net Realized Gains (Losses): Gross Realized Gains $ 2 $ 17 $ 6 Gross Realized Losses (4 ) (5 ) (5 ) Net Realized Gains (Losses) on Rabbi Trust (B) (2 ) 12 1 Unrealized Gains (Losses) on Equity Securities in Rabbi Trust (C) (2 ) N/A N/A Net Gains (Losses) on Rabbi Trust Investments $ (4 ) $ 12 $ 1 (A) Includes activity in accounts related to the liquidation of funds being transitioned to new managers. (B) The cost of these securities was determined on the basis of specific identification. (C) Effective January 1, 2018, unrealized gains (losses) on equity securities are recorded in Net Income instead of Other Comprehensive Income (Loss). The Rabbi Trust debt securities held as of December 31, 2018 had the following maturities: Time Frame Fair Value Millions Less than one year $ 1 1 - 5 years 35 6 - 10 years 27 11 - 15 years 8 16 - 20 years 21 Over 20 years 109 Total Rabbi Trust Available-for-Sale Debt Securities $ 201 PSEG periodically assesses individual debt securities whose fair value is less than amortized cost to determine whether the investments are considered to be other-than-temporarily impaired. For these securities, management considers its intent to sell or requirement to sell a security prior to expected recovery. In those cases where a sale is expected, any impairment would be recorded through earnings. For fixed income securities where there is no intent to sell or likely requirement to sell, management evaluates whether credit loss is a component of the impairment. If so, that portion is recorded through earnings while the noncredit loss component is recorded through Accumulated Other Comprehensive Income (Loss). The assessment of fair market value compared to cost is applied on a weighted average basis taking into account various purchase dates and initial cost of the securities. The fair value of the Rabbi Trust related to PSEG, PSE&G and Power are detailed as follows: As of December 31, As of December 31, 2018 2017 Millions PSE&G $ 45 $ 46 Power 56 57 Other 123 128 Total Rabbi Trust Investments $ 224 $ 231
Power [Member]
Schedule of Trust Investments [Line Items]
Trust Investments [Text Block]	NDT Fund In accordance with NRC regulations, entities owning an interest in nuclear generating facilities are required to determine the costs and funding methods necessary to decommission such facilities upon termination of operation. As a general practice, each nuclear owner places funds in independent external trust accounts it maintains to provide for decommissioning. Power is required to file periodic reports with the NRC demonstrating that its NDT Fund meets the formula-based minimum NRC funding requirements. Power maintains an external master NDT to fund its share of decommissioning for its five nuclear facilities upon their respective termination of operation. The trust contains two separate funds: a qualified fund and a non-qualified fund. Section 468A of the Internal Revenue Code limits the amount of money that can be contributed into a qualified fund. Power’s share of decommissioning costs related to its five nuclear units was estimated to be between $2.8 billion and $3.0 billion , including contingencies. The liability for decommissioning recorded on a discounted basis as of December 31, 2018 was approximately $708 million and is included in the Asset Retirement Obligation. The funds are managed by third-party investment managers who operate under investment guidelines developed by Power. The following tables show the fair values and gross unrealized gains and losses for the securities held in the NDT Fund. As of December 31, 2018 Cost Gross Unrealized Gains Gross Unrealized Losses Fair Value Millions Equity Securities Domestic $ 447 $ 153 $ (29 ) $ 571 International 323 36 (30 ) 329 Total Equity Securities 770 189 (59 ) 900 Available-for Sale Debt Securities Government 498 2 (9 ) 491 Corporate 501 1 (15 ) 487 Total Available-for-Sale Debt Securities 999 3 (24 ) 978 Total NDT Fund Investments $ 1,769 $ 192 $ (83 ) $ 1,878 As of December 31, 2017 Cost Gross Unrealized Gains Gross Unrealized Losses Fair Value Millions Equity Securities Domestic $ 497 $ 245 $ (2 ) $ 740 International 311 99 — (3 ) 407 Total Equity Securities 808 344 (5 ) 1,147 Available-for Sale Debt Securities Government 586 2 (4 ) 584 Corporate 400 4 (2 ) 402 Total Available-for-Sale Debt Securities 986 6 (6 ) 986 Total NDT Fund Investments $ 1,794 $ 350 $ (11 ) $ 2,133 Net unrealized gains (losses) on debt securities of $(12) million (after-tax) were included in Accumulated Other Comprehensive Loss on PSEG’s and Power’s Consolidated Balance Sheets as of December 31, 2018 . The portion of net unrealized gains (losses) recognized during 2018 related to equity securities still held at the end of December 31, 2018 was $(127) million . The amounts in the preceding tables do not include receivables and payables for NDT Fund transactions which have not settled at the end of each period. Such amounts are included in Accounts Receivable and Accounts Payable on the Consolidated Balance Sheets as shown in the following table. As of December 31, 2018 As of December 31, 2017 Millions Accounts Receivable $ 17 $ 24 Accounts Payable $ 5 $ 74 The following table shows the value of securities in the NDT Fund that have been in an unrealized loss position for less than and greater than 12 months. As of December 31, 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 Equity Securities (A) Domestic $ 147 $ (26 ) $ 5 $ (3 ) $ 40 $ (2 ) $ — $ — International 131 (28 ) 5 (2 ) 29 (3 ) 2 — Total Equity Securities 278 (54 ) 10 (5 ) 69 (5 ) 2 — Available-for-Sale Debt Securities Government (B) 51 — 317 (9 ) 343 (2 ) 91 (2 ) Corporate (C) 150 (5 ) 222 (10 ) 191 (1 ) 27 (1 ) Total Available-for-Sale Debt Securities 201 (5 ) 539 (19 ) 534 (3 ) 118 (3 ) NDT Trust Investments $ 479 $ (59 ) $ 549 $ (24 ) $ 603 $ (8 ) $ 120 $ (3 ) (A) Equity Securities—Investments in marketable equity securities within the NDT Fund are primarily in common stocks within a broad range of industries and sectors. Effective January 1, 2018, unrealized gains and losses on these securities are recorded in Net Income. (B) Debt Securities (Government)—Unrealized gains and losses on these securities are recorded in Accumulated Other Comprehensive Income (Loss). The unrealized losses on Power’s NDT investments in U.S. Treasury obligations and Federal Agency mortgage-backed securities were caused by interest rate changes. These investments are guaranteed by the U.S. government or an agency of the U.S. government. Power also has investments in municipal bonds that are primarily in investment grade securities. It is not expected that these securities will settle for less than their amortized cost. Since Power does not intend to sell these securities nor will it be more-likely-than-not required to sell, Power does not consider these debt securities to be other-than-temporarily impaired as of December 31, 2018 . (C) Debt Securities (Corporate)—Unrealized gains and losses on these securities are recorded in Accumulated Other Comprehensive Income (Loss). Power’s investments in corporate bonds are primarily in investment grade securities. It is not expected that these securities would settle for less than their amortized cost. Since Power does not intend to sell these securities nor will it be more-likely-than-not required to sell, Power does not consider these debt securities to be other-than-temporarily impaired as of December 31, 2018 . The proceeds from the sales of and the net gains (losses) on securities in the NDT Fund were: Years Ended December 31, 2018 2017 2016 Millions Proceeds from Sales (A) $ 1,398 $ 2,137 $ 711 Net Realized Gains (Losses): Gross Realized Gains $ 121 $ 157 $ 53 Gross Realized Losses (51 ) (23 ) (32 ) Net Realized Gains (Losses) on NDT Fund (B) $ 70 $ 134 $ 21 Unrealized Gains (Losses) on Equity Securities in NDT Fund (C) (209 ) N/A N/A Other-Than-Temporary-Impairments (OTTI) — (12 ) (28 ) Net Gains (Losses) on NDT Fund Investments $ (139 ) $ 122 $ (7 ) (A) Includes activity in accounts related to the liquidation of funds being transitioned to new managers. (B) The cost of these securities was determined on the basis of specific identification. (C) Effective January 1, 2018, unrealized gains (losses) on equity securities are recorded in Net Income instead of Other Comprehensive Income (Loss). The NDT Fund debt securities held as of December 31, 2018 had the following maturities: Time Frame Fair Value Millions Less than one year $ 13 1 - 5 years 254 6 - 10 years 211 11 - 15 years 40 16 - 20 years 77 Over 20 years 383 Total NDT Available-for-Sale Debt Securities $ 978 Power periodically assesses individual debt securities whose fair value is less than amortized cost to determine whether the investments are considered to be other-than-temporarily impaired. For these securities, management considers its intent to sell or requirement to sell a security prior to expected recovery. In those cases where a sale is expected, any impairment would be recorded through earnings. For fixed income securities where there is no intent to sell or likely requirement to sell, management evaluates whether credit loss is a component of the impairment. If so, that portion is recorded through earnings while the noncredit loss component is recorded through Accumulated Other Comprehensive Income (Loss). Any subsequent recoveries in the value of these securities would be recognized in Accumulated Other Comprehensive Income (Loss) unless the securities are sold, in which case, any gain would be recognized in income. The assessment of fair market value compared to cost is applied on a weighted average basis taking into account various purchase dates and initial cost of the securities. Rabbi Trust PSEG maintains certain unfunded nonqualified benefit plans to provide supplemental retirement and deferred compensation benefits to certain key employees. Certain assets related to these plans have been set aside in a grantor trust commonly known as a “Rabbi Trust.” The following tables show the fair values, gross unrealized gains and losses and amortized cost basis for the securities held in the Rabbi Trust. As of December 31, 2018 Cost Gross Unrealized Gains Gross Unrealized Losses Fair Value Millions Equity Securities Domestic $ 22 $ 1 $ — $ 23 International — — — — Total Equity Securities 22 1 — 23 Available-for-Sale Debt Securities Government 110 1 (2 ) 109 Corporate 96 — (4 ) 92 Total Available-for-Sale Debt Securities 206 1 (6 ) 201 Total Rabbi Trust Investments $ 228 $ 2 $ (6 ) $ 224 As of December 31, 2017 Cost Gross Unrealized Gains Gross Unrealized Losses Fair Value Millions Equity Securities Domestic $ 24 $ 3 $ — $ 27 International — — — — Total Equity Securities 24 3 — 27 Available-for-Sale Debt Securities Government 85 1 (1 ) 85 Corporate 118 2 (1 ) 119 Total Available-for-Sale Debt Securities 203 3 (2 ) 204 Total Rabbi Trust Investments $ 227 $ 6 $ (2 ) $ 231 Net unrealized gains (losses) on debt securities of $(4) million (after-tax) were included in Accumulated Other Comprehensive Loss on PSEG’s Consolidated Balance Sheet as of December 31, 2018 . The portion of net unrealized gains (losses) recognized during 2018 related to equity securities still held at the end of December 31, 2018 was $(2) million . The amounts in the preceding tables do not include receivables and payables for Rabbi Trust Fund transactions which have not settled at the end of each period. Such amounts are included in Accounts Receivable and Accounts Payable on the Consolidated Balance Sheets as shown in the following table. As of December 31, 2018 As of December 31, 2017 Millions Accounts Receivable $ 2 $ 2 Accounts Payable $ — $ 1 The following table shows the value of securities in the Rabbi Trust Fund that have been in an unrealized loss position for less than and greater than 12 months: As of December 31, 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) $ 18 $ — $ 59 $ (2 ) $ 28 $ — $ 25 $ (1 ) Corporate (B) 50 (3 ) 29 (1 ) 39 (1 ) 9 — Total Available-for-Sale Debt Securities 68 (3 ) 88 (3 ) 67 (1 ) 34 (1 ) Rabbi Trust Investments $ 68 $ (3 ) $ 88 $ (3 ) $ 67 $ (1 ) $ 34 $ (1 ) (A) Debt Securities (Government)—Unrealized gains and losses on these securities are recorded in Accumulated Other Comprehensive Income (Loss). The unrealized losses on PSEG’s Rabbi Trust investments in U.S. Treasury obligations and Federal Agency mortgage-backed securities were caused by interest rate changes. These investments are guaranteed by the U.S. government or an agency of the U.S. government. PSEG also has investments in municipal bonds that are primarily in investment grade securities. It is not expected that these securities will settle for less than their amortized cost. Since PSEG does not intend to sell these securities nor will it be more-likely-than-not required to sell, PSEG does not consider these debt securities to be other-than-temporarily impaired as of December 31, 2018 . (B) Debt Securities (Corporate)—Unrealized gains and losses on these securities are recorded in Accumulated Other Comprehensive Income (Loss). PSEG’s investments in corporate bonds are primarily in investment grade securities. It is not expected that these securities would settle for less than their amortized cost. Since PSEG does not intend to sell these securities nor will it be more-likely-than-not required to sell, PSEG does not consider these debt securities to be other-than-temporarily impaired as of December 31, 2018 . The proceeds from the sales of and the net gains (losses) on securities in the Rabbi Trust Fund were: Years Ended December 31, 2018 2017 2016 Millions Proceeds from Rabbi Trust Sales (A) $ 103 $ 182 $ 113 Net Realized Gains (Losses): Gross Realized Gains $ 2 $ 17 $ 6 Gross Realized Losses (4 ) (5 ) (5 ) Net Realized Gains (Losses) on Rabbi Trust (B) (2 ) 12 1 Unrealized Gains (Losses) on Equity Securities in Rabbi Trust (C) (2 ) N/A N/A Net Gains (Losses) on Rabbi Trust Investments $ (4 ) $ 12 $ 1 (A) Includes activity in accounts related to the liquidation of funds being transitioned to new managers. (B) The cost of these securities was determined on the basis of specific identification. (C) Effective January 1, 2018, unrealized gains (losses) on equity securities are recorded in Net Income instead of Other Comprehensive Income (Loss). The Rabbi Trust debt securities held as of December 31, 2018 had the following maturities: Time Frame Fair Value Millions Less than one year $ 1 1 - 5 years 35 6 - 10 years 27 11 - 15 years 8 16 - 20 years 21 Over 20 years 109 Total Rabbi Trust Available-for-Sale Debt Securities $ 201 PSEG periodically assesses individual debt securities whose fair value is less than amortized cost to determine whether the investments are considered to be other-than-temporarily impaired. For these securities, management considers its intent to sell or requirement to sell a security prior to expected recovery. In those cases where a sale is expected, any impairment would be recorded through earnings. For fixed income securities where there is no intent to sell or likely requirement to sell, management evaluates whether credit loss is a component of the impairment. If so, that portion is recorded through earnings while the noncredit loss component is recorded through Accumulated Other Comprehensive Income (Loss). The assessment of fair market value compared to cost is applied on a weighted average basis taking into account various purchase dates and initial cost of the securities. The fair value of the Rabbi Trust related to PSEG, PSE&G and Power are detailed as follows: As of December 31, As of December 31, 2018 2017 Millions PSE&G $ 45 $ 46 Power 56 57 Other 123 128 Total Rabbi Trust Investments $ 224 $ 231

Goodwill And Other Intangibles

Goodwill And Other Intangibles	12 Months Ended
	Dec. 31, 2018
Goodwill [Line Items]
Goodwill And Other Intangibles	Goodwill and Other Intangibles As of December 31, 2018 and 2017 , Power had goodwill of $ 16 million related to the Bethlehem Energy Center facility. Power conducted an annual review for goodwill impairment in the fourth quarter of 2018 and concluded that goodwill continues to remain unimpaired. In addition to goodwill, as of December 31, 2018 and 2017 , Power had intangible assets of $ 143 million and $ 114 million , respectively, related to emissions allowances and RECs. Emissions allowances and RECs are recorded at cost and evaluated for impairment at least annually. Emissions expense includes impairments of emissions allowances, if any, and costs for emissions, which is recorded as emissions occur. As load is served under contracts requiring energy from renewable sources, the related expense is recorded. The changes to Power’s intangible assets during 2017 and 2018 are presented in the following table: Emissions Allowances RECs Total Other Intangibles Millions Balance as of January 1, 2017 $ 54 $ 44 $ 98 Retirements (7 ) (93 ) (100 ) Purchases 27 90 117 Sales and Transfers, net — (1 ) (1 ) Balance as of December 31, 2017 $ 74 $ 40 $ 114 Retirements (26 ) (90 ) (116 ) Purchases 36 110 146 Sales and Transfers, net — (1 ) (1 ) Balance as of December 31, 2018 $ 84 $ 59 $ 143
Power [Member]
Goodwill [Line Items]
Goodwill And Other Intangibles	Goodwill and Other Intangibles As of December 31, 2018 and 2017 , Power had goodwill of $ 16 million related to the Bethlehem Energy Center facility. Power conducted an annual review for goodwill impairment in the fourth quarter of 2018 and concluded that goodwill continues to remain unimpaired. In addition to goodwill, as of December 31, 2018 and 2017 , Power had intangible assets of $ 143 million and $ 114 million , respectively, related to emissions allowances and RECs. Emissions allowances and RECs are recorded at cost and evaluated for impairment at least annually. Emissions expense includes impairments of emissions allowances, if any, and costs for emissions, which is recorded as emissions occur. As load is served under contracts requiring energy from renewable sources, the related expense is recorded. The changes to Power’s intangible assets during 2017 and 2018 are presented in the following table: Emissions Allowances RECs Total Other Intangibles Millions Balance as of January 1, 2017 $ 54 $ 44 $ 98 Retirements (7 ) (93 ) (100 ) Purchases 27 90 117 Sales and Transfers, net — (1 ) (1 ) Balance as of December 31, 2017 $ 74 $ 40 $ 114 Retirements (26 ) (90 ) (116 ) Purchases 36 110 146 Sales and Transfers, net — (1 ) (1 ) Balance as of December 31, 2018 $ 84 $ 59 $ 143

Asset Retirement Obligations (A

Asset Retirement Obligations (AROs)	12 Months Ended
	Dec. 31, 2018
Asset Retirement Obligation [Line Items]
Asset Retirement Obligations (AROs)	Asset Retirement Obligations (AROs) PSEG, PSE&G and Power recognize liabilities for the expected cost of retiring long-lived assets for which a legal obligation exists to remove or dispose of an asset or some component of an asset at retirement. These AROs are recorded at fair value in the period in which they are incurred and are capitalized as part of the carrying amount of the related long-lived assets. PSE&G, as a rate-regulated entity, recognizes Regulatory Assets or Liabilities as a result of timing differences between the recording of costs and costs recovered through the rate-making process. We accrete the ARO liability to reflect the passage of time with the corresponding expense recorded in O&M. PSE&G has conditional AROs primarily for legal obligations related to the removal of treated wood poles and the requirement to seal natural gas pipelines at all sources of gas when the pipelines are no longer in service. PSE&G does not record an ARO for its protected steel and poly-based natural gas lines, as management believes that these categories of gas lines have an indeterminable life. Power’s ARO liability primarily relates to the decommissioning of its nuclear power plants in accordance with NRC requirements. Power has an independent external trust that is intended to fund decommissioning of its nuclear facilities upon termination of operation. For additional information, see Note 10. Trust Investments . Power also identified conditional AROs primarily related to Power’s fossil generation units and solar facilities, including liabilities for removal of asbestos, ash ponds, stored hazardous liquid material and underground storage tanks from industrial power sites, and demolition of certain plants, and the restoration of the sites at which they reside, when the plants are no longer in service. To estimate the fair value of its AROs, Power uses a probability weighted, discounted cash flow model which, on a unit by unit basis, considers multiple outcome scenarios that include significant estimates and assumptions, and are based on third-party decommissioning cost estimates, cost escalation rates, inflation rates and discount rates. Updated cost studies are obtained triennially unless new information necessitates more frequent updates. The most recent cost study was done in 2018. When assumptions are revised to calculate fair values of existing AROs, generally, the ARO balance and corresponding long-lived asset are adjusted which impact the amount of accretion and depreciation expense recognized in future periods. For PSE&G, Regulatory Assets and Regulatory Liabilities result when accretion and amortization are adjusted to match rates established by regulators resulting in the regulatory deferral of any gain or loss. The changes to the ARO liabilities for PSEG, PSE&G and Power during 2017 and 2018 are presented in the following table: PSEG PSE&G Power Other Millions ARO Liability as of January 1, 2017 $ 726 $ 213 $ 511 $ 2 Liabilities Settled (29 ) (8 ) (21 ) — Liabilities Incurred 1 — 1 — Accretion Expense 30 — 30 — Accretion Expense Deferred and Recovered in Rate Base (A) 12 12 — — Revision to Present Values of Estimated Cash Flows 284 (5 ) 289 — ARO Liability as of December 31, 2017 $ 1,024 $ 212 $ 810 $ 2 Liabilities Settled (10 ) (9 ) (1 ) — Liabilities Incurred 1 — 1 — Accretion Expense 41 — 41 — Accretion Expense Deferred and Recovered in Rate Base (A) 12 12 — — Revision to Present Values of Estimated Cash Flows (5 ) 87 (93 ) 1 ARO Liability as of December 31, 2018 $ 1,063 $ 302 $ 758 $ 3 (A) Not reflected as expense in Consolidated Statements of Operations During 2018 , PSE&G recorded an increase to its ARO liabilities primarily due to the impact of an increase in labor rates. These changes had no impact in PSE&G’s Consolidated Statement of Operations . During 2017 , Power recorded an increase to its ARO liabilities primarily due to a higher assumed probability of early retirement of its nuclear units of $276 million . During 2018 , Power recorded a reduction to its ARO liabilities, primarily due to changes in discount rates and decommissioning assumptions related to nuclear. The changes in decommissioning assumptions, including a reduction for the lower probability of early retirement of the nuclear units, were due in part to the enactment of the New Jersey ZEC legislation in May 2018 and that the Salem and Hope Creek Units were the sole applicants under the ZEC program. This reduction was also due to the sale of the Hudson and Mercer units, partially offset by increases in estimated costs to decommission Power’s fossil units pursuant to its most recent cost study. These changes had an immaterial impact in Power’s Consolidated Statement of Operations. See Note 4. Early Plant Retirements for additional information.
PSE&G [Member]
Asset Retirement Obligation [Line Items]
Asset Retirement Obligations (AROs)	Asset Retirement Obligations (AROs) PSEG, PSE&G and Power recognize liabilities for the expected cost of retiring long-lived assets for which a legal obligation exists to remove or dispose of an asset or some component of an asset at retirement. These AROs are recorded at fair value in the period in which they are incurred and are capitalized as part of the carrying amount of the related long-lived assets. PSE&G, as a rate-regulated entity, recognizes Regulatory Assets or Liabilities as a result of timing differences between the recording of costs and costs recovered through the rate-making process. We accrete the ARO liability to reflect the passage of time with the corresponding expense recorded in O&M. PSE&G has conditional AROs primarily for legal obligations related to the removal of treated wood poles and the requirement to seal natural gas pipelines at all sources of gas when the pipelines are no longer in service. PSE&G does not record an ARO for its protected steel and poly-based natural gas lines, as management believes that these categories of gas lines have an indeterminable life. Power’s ARO liability primarily relates to the decommissioning of its nuclear power plants in accordance with NRC requirements. Power has an independent external trust that is intended to fund decommissioning of its nuclear facilities upon termination of operation. For additional information, see Note 10. Trust Investments . Power also identified conditional AROs primarily related to Power’s fossil generation units and solar facilities, including liabilities for removal of asbestos, ash ponds, stored hazardous liquid material and underground storage tanks from industrial power sites, and demolition of certain plants, and the restoration of the sites at which they reside, when the plants are no longer in service. To estimate the fair value of its AROs, Power uses a probability weighted, discounted cash flow model which, on a unit by unit basis, considers multiple outcome scenarios that include significant estimates and assumptions, and are based on third-party decommissioning cost estimates, cost escalation rates, inflation rates and discount rates. Updated cost studies are obtained triennially unless new information necessitates more frequent updates. The most recent cost study was done in 2018. When assumptions are revised to calculate fair values of existing AROs, generally, the ARO balance and corresponding long-lived asset are adjusted which impact the amount of accretion and depreciation expense recognized in future periods. For PSE&G, Regulatory Assets and Regulatory Liabilities result when accretion and amortization are adjusted to match rates established by regulators resulting in the regulatory deferral of any gain or loss. The changes to the ARO liabilities for PSEG, PSE&G and Power during 2017 and 2018 are presented in the following table: PSEG PSE&G Power Other Millions ARO Liability as of January 1, 2017 $ 726 $ 213 $ 511 $ 2 Liabilities Settled (29 ) (8 ) (21 ) — Liabilities Incurred 1 — 1 — Accretion Expense 30 — 30 — Accretion Expense Deferred and Recovered in Rate Base (A) 12 12 — — Revision to Present Values of Estimated Cash Flows 284 (5 ) 289 — ARO Liability as of December 31, 2017 $ 1,024 $ 212 $ 810 $ 2 Liabilities Settled (10 ) (9 ) (1 ) — Liabilities Incurred 1 — 1 — Accretion Expense 41 — 41 — Accretion Expense Deferred and Recovered in Rate Base (A) 12 12 — — Revision to Present Values of Estimated Cash Flows (5 ) 87 (93 ) 1 ARO Liability as of December 31, 2018 $ 1,063 $ 302 $ 758 $ 3 (A) Not reflected as expense in Consolidated Statements of Operations During 2018 , PSE&G recorded an increase to its ARO liabilities primarily due to the impact of an increase in labor rates. These changes had no impact in PSE&G’s Consolidated Statement of Operations . During 2017 , Power recorded an increase to its ARO liabilities primarily due to a higher assumed probability of early retirement of its nuclear units of $276 million . During 2018 , Power recorded a reduction to its ARO liabilities, primarily due to changes in discount rates and decommissioning assumptions related to nuclear. The changes in decommissioning assumptions, including a reduction for the lower probability of early retirement of the nuclear units, were due in part to the enactment of the New Jersey ZEC legislation in May 2018 and that the Salem and Hope Creek Units were the sole applicants under the ZEC program. This reduction was also due to the sale of the Hudson and Mercer units, partially offset by increases in estimated costs to decommission Power’s fossil units pursuant to its most recent cost study. These changes had an immaterial impact in Power’s Consolidated Statement of Operations. See Note 4. Early Plant Retirements for additional information.
Power [Member]
Asset Retirement Obligation [Line Items]
Asset Retirement Obligations (AROs)	Asset Retirement Obligations (AROs) PSEG, PSE&G and Power recognize liabilities for the expected cost of retiring long-lived assets for which a legal obligation exists to remove or dispose of an asset or some component of an asset at retirement. These AROs are recorded at fair value in the period in which they are incurred and are capitalized as part of the carrying amount of the related long-lived assets. PSE&G, as a rate-regulated entity, recognizes Regulatory Assets or Liabilities as a result of timing differences between the recording of costs and costs recovered through the rate-making process. We accrete the ARO liability to reflect the passage of time with the corresponding expense recorded in O&M. PSE&G has conditional AROs primarily for legal obligations related to the removal of treated wood poles and the requirement to seal natural gas pipelines at all sources of gas when the pipelines are no longer in service. PSE&G does not record an ARO for its protected steel and poly-based natural gas lines, as management believes that these categories of gas lines have an indeterminable life. Power’s ARO liability primarily relates to the decommissioning of its nuclear power plants in accordance with NRC requirements. Power has an independent external trust that is intended to fund decommissioning of its nuclear facilities upon termination of operation. For additional information, see Note 10. Trust Investments . Power also identified conditional AROs primarily related to Power’s fossil generation units and solar facilities, including liabilities for removal of asbestos, ash ponds, stored hazardous liquid material and underground storage tanks from industrial power sites, and demolition of certain plants, and the restoration of the sites at which they reside, when the plants are no longer in service. To estimate the fair value of its AROs, Power uses a probability weighted, discounted cash flow model which, on a unit by unit basis, considers multiple outcome scenarios that include significant estimates and assumptions, and are based on third-party decommissioning cost estimates, cost escalation rates, inflation rates and discount rates. Updated cost studies are obtained triennially unless new information necessitates more frequent updates. The most recent cost study was done in 2018. When assumptions are revised to calculate fair values of existing AROs, generally, the ARO balance and corresponding long-lived asset are adjusted which impact the amount of accretion and depreciation expense recognized in future periods. For PSE&G, Regulatory Assets and Regulatory Liabilities result when accretion and amortization are adjusted to match rates established by regulators resulting in the regulatory deferral of any gain or loss. The changes to the ARO liabilities for PSEG, PSE&G and Power during 2017 and 2018 are presented in the following table: PSEG PSE&G Power Other Millions ARO Liability as of January 1, 2017 $ 726 $ 213 $ 511 $ 2 Liabilities Settled (29 ) (8 ) (21 ) — Liabilities Incurred 1 — 1 — Accretion Expense 30 — 30 — Accretion Expense Deferred and Recovered in Rate Base (A) 12 12 — — Revision to Present Values of Estimated Cash Flows 284 (5 ) 289 — ARO Liability as of December 31, 2017 $ 1,024 $ 212 $ 810 $ 2 Liabilities Settled (10 ) (9 ) (1 ) — Liabilities Incurred 1 — 1 — Accretion Expense 41 — 41 — Accretion Expense Deferred and Recovered in Rate Base (A) 12 12 — — Revision to Present Values of Estimated Cash Flows (5 ) 87 (93 ) 1 ARO Liability as of December 31, 2018 $ 1,063 $ 302 $ 758 $ 3 (A) Not reflected as expense in Consolidated Statements of Operations During 2018 , PSE&G recorded an increase to its ARO liabilities primarily due to the impact of an increase in labor rates. These changes had no impact in PSE&G’s Consolidated Statement of Operations . During 2017 , Power recorded an increase to its ARO liabilities primarily due to a higher assumed probability of early retirement of its nuclear units of $276 million . During 2018 , Power recorded a reduction to its ARO liabilities, primarily due to changes in discount rates and decommissioning assumptions related to nuclear. The changes in decommissioning assumptions, including a reduction for the lower probability of early retirement of the nuclear units, were due in part to the enactment of the New Jersey ZEC legislation in May 2018 and that the Salem and Hope Creek Units were the sole applicants under the ZEC program. This reduction was also due to the sale of the Hudson and Mercer units, partially offset by increases in estimated costs to decommission Power’s fossil units pursuant to its most recent cost study. These changes had an immaterial impact in Power’s Consolidated Statement of Operations. See Note 4. Early Plant Retirements for additional information.

Pension, OPEB and Savings Plans

Pension, OPEB and Savings Plans	12 Months Ended
	Dec. 31, 2018
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension, OPEB and Savings Plans	Pension, Other Postretirement Benefits (OPEB) and Savings Plans PSEG sponsors qualified and nonqualified pension plans and OPEB plans covering PSEG’s and its participating affiliates’ current and former employees who meet certain eligibility criteria. Eligible employees participate in non-contributory pension and OPEB plans sponsored by PSEG and administered by Services. In addition, represented and nonrepresented employees are eligible for participation in PSEG’s two defined contribution plans described below. PSEG, PSE&G and Power are required to record the under or over funded positions of their defined benefit pension and OPEB plans on their respective balance sheets. Such funding positions of each PSEG company are required to be measured as of the date of its respective year-end Consolidated Balance Sheets. For underfunded plans, the liability is equal to the difference between the plan’s benefit obligation and the fair value of plan assets. For defined benefit pension plans, the benefit obligation is the projected benefit obligation. For OPEB plans, the benefit obligation is the accumulated postretirement benefit obligation. In addition, GAAP requires that the total unrecognized costs for defined benefit pension and OPEB plans be recorded as an after-tax charge to Accumulated Other Comprehensive Income (Loss), a separate component of Stockholders’ Equity. However, for PSE&G, because the amortization of the unrecognized costs is being collected from customers, the accumulated unrecognized costs are recorded as a Regulatory Asset. The unrecognized costs represent actuarial gains or losses and prior service costs which had not been expensed. For PSE&G, the Regulatory Asset is amortized and recorded as net periodic pension cost in the Consolidated Statements of Operations. For Power, the charge to Accumulated Other Comprehensive Income (Loss) is amortized and recorded as net periodic pension cost in the Consolidated Statements of Operations. In December 2018, PSEG amended certain provisions of its OPEB plans applicable to all current and future Medicare-eligible retirees and spouses who receive or will receive subsidized healthcare from PSEG. Effective January 1, 2021, the PSEG-sponsored Medicare-eligible plans will be replaced by a Medicare private exchange. For each Medicare-eligible retiree and spouse, PSEG will provide annual credits to a Health Reimbursement Arrangement, which can be used to pay for medical, prescription drug, and dental plan premiums, as well as certain out-of-pocket costs. The amendment resulted in a $559 million reduction in PSEG’s OPEB obligation as of December 31, 2018 . Amounts for Servco are not included in any of the following pension and OPEB benefit information for PSEG and its affiliates but rather are separately disclosed later in this note. The following table provides a roll-forward of the changes in the benefit obligation and the fair value of plan assets during each of the two years in the periods ended December 31, 2018 and 2017 . It also provides the funded status of the plans and the amounts recognized and amounts not recognized on the Consolidated Balance Sheets at the end of both years. Pension Benefits Other Benefits 2018 2017 2018 2017 Millions Change in Benefit Obligation Benefit Obligation at Beginning of Year (A) $ 6,359 $ 5,772 $ 1,976 $ 1,754 Service Cost 130 114 18 17 Interest Cost 208 204 66 63 Actuarial (Gain) Loss (460 ) 564 (222 ) 199 Gross Benefits Paid (316 ) (295 ) (76 ) (57 ) Plan Amendments — — (559 ) — Benefit Obligation at End of Year (A) $ 5,921 $ 6,359 $ 1,203 $ 1,976 Change in Plan Assets Fair Value of Assets at Beginning of Year $ 5,812 $ 5,193 $ 511 $ 420 Actual Return on Plan Assets (388 ) 903 (36 ) 77 Employer Contributions 12 11 89 71 Gross Benefits Paid (316 ) (295 ) (76 ) (57 ) Fair Value of Assets at End of Year $ 5,120 $ 5,812 $ 488 $ 511 Funded Status Funded Status (Plan Assets less Benefit Obligation) $ (801 ) $ (547 ) $ (715 ) $ (1,465 ) Additional Amounts Recognized in the Consolidated Balance Sheets Current Accrued Benefit Cost (10 ) (10 ) (11 ) (10 ) Noncurrent Accrued Benefit Cost (791 ) (537 ) (704 ) (1,455 ) Amounts Recognized $ (801 ) $ (547 ) $ (715 ) $ (1,465 ) Additional Amounts Recognized in Accumulated Other Comprehensive Income (Loss), Regulated Assets and Deferred Assets (B) Prior Service Cost $ (28 ) $ (46 ) $ (561 ) $ (3 ) Net Actuarial Loss 2,005 1,721 420 629 Total $ 1,977 $ 1,675 $ (141 ) $ 626 (A) Represents projected benefit obligation for pension benefits and the accumulated postretirement benefit obligation for other benefits. The vested benefit obligation is the actuarial present value of the vested benefits to which the employee is currently entitled but based on the employee’s expected date of separation of retirement. (B) Includes $ 619 million ($ 360 million , after-tax) and $ 683 million ($ 406 million , after-tax) in Accumulated Other Comprehensive Loss related to Pension and OPEB as of December 31, 2018 and 2017 , respectively. Also includes Regulatory Assets of $1,090 million and Deferred Assets of $127 million as of December 31, 2018 and Regulatory Assets of $1,485 million and Deferred Assets of $133 million as of December 31, 2017 . The pension benefits table above provides information relating to the funded status of the qualified and nonqualified pension and OPEB plans on an aggregate basis. As of December 31, 2018 , PSEG had funded approximately 86% of its projected benefit obligation. This percentage does not include $ 224 million of assets in the Rabbi Trust as of December 31, 2018 which were used partially to fund the nonqualified pension plans. As of December 31, 2018 , the nonqualified pension plans included in the projected benefit obligation in the above table were $156 million . Accumulated Benefit Obligation The accumulated benefit obligation for all PSEG’s defined benefit pension plans was $ 5.7 billion as of December 31, 2018 and $ 6.1 billion as of December 31, 2017 . The following table provides the components of net periodic benefit cost relating to all qualified and nonqualified pension and OPEB plans on an aggregate basis for PSEG, excluding Servco for the years ended December 31, 2018 , 2017 and 2016 . Amounts shown do not reflect the impacts of capitalization and co-owner allocations. Effective with the adoption of ASU 2017-07 on January 1, 2018, only the service cost component is eligible for capitalization, when applicable. For additional information, see Note 2. Recent Accounting Standards . Pension Benefits Years Ended December 31, Other Benefits Years Ended December 31, 2018 2017 2016 2018 2017 2016 Millions Components of Net Periodic Benefit (Credits) Costs Service Cost (included in O&M Expense) $ 130 $ 114 $ 109 $ 18 $ 17 $ 17 Non-Service Components of Pension and OPEB (Credits) Costs Interest Cost 208 204 202 66 63 59 Expected Return on Plan Assets (441 ) (394 ) (394 ) (41 ) (34 ) (31 ) Amortization of Net Prior Service Credit (18 ) (18 ) (19 ) (1 ) (11 ) (14 ) Actuarial Loss 85 97 158 64 51 40 Non-Service Components of Pension and OPEB (Credits) Costs (166 ) (111 ) (53 ) 88 69 54 Total Benefit (Credits) Costs $ (36 ) $ 3 $ 56 $ 106 $ 86 $ 71 Pension costs and OPEB costs for PSEG, PSE&G and Power are detailed as follows: Pension Benefits Years Ended December 31, Other Benefits Years Ended December 31, 2018 2017 2016 2018 2017 2016 Millions PSE&G $ (31 ) $ (4 ) $ 29 $ 68 $ 54 $ 43 Power (9 ) 1 16 32 27 23 Other 4 6 11 6 5 5 Total Benefit (Credits) Costs $ (36 ) $ 3 $ 56 $ 106 $ 86 $ 71 The following table provides the pre-tax changes recognized in Accumulated Other Comprehensive Income (Loss), Regulatory Assets and Deferred Assets: Pension OPEB 2018 2017 2018 2017 Millions Net Actuarial (Gain) Loss in Current Period $ 369 $ 55 $ (145 ) $ 156 Amortization of Net Actuarial Gain (Loss) (85 ) (97 ) (64 ) (50 ) Prior Service Cost (Credit) in current period — — (559 ) — Amortization of Prior Service Credit 18 18 1 11 Total $ 302 $ (24 ) $ (767 ) $ 117 Amounts that are expected to be amortized from Accumulated Other Comprehensive Loss, Regulatory Assets and Deferred Assets into Net Periodic Benefit Cost in 2019 are as follows: Pension Benefits Other Benefits 2019 2019 Millions Actuarial Loss $ 107 $ 50 Prior Service Credit $ (18 ) $ (128 ) The following assumptions were used to determine the benefit obligations and net periodic benefit costs: Pension Benefits Other Benefits 2018 2017 2016 2018 2017 2016 Weighted-Average Assumptions Used to Determine Benefit Obligations as of December 31 Discount Rate 4.41 % 3.73 % 4.29 % 4.31 % 3.76 % 4.37 % Rate of Compensation Increase 3.90 % 3.90 % 3.61 % 3.90 % 3.90 % 3.61 % Weighted-Average Assumptions Used to Determine Net Periodic Benefit Cost for Years Ended December 31 Discount Rate 3.73 % 4.29 % 4.54 % 3.76 % 4.37 % 4.58 % Service Cost Interest Rate 3.88 % 4.53 % 4.81 % 3.90 % 4.64 % 4.87 % Interest Cost Interest Rate 3.35 % 3.63 % 3.75 % 3.39 % 3.69 % 3.76 % Expected Return on Plan Assets 7.80 % 7.80 % 8.00 % 7.80 % 7.80 % 8.00 % Rate of Compensation Increase 3.90 % 3.61 % 3.61 % 3.90 % 3.61 % 3.61 % Assumed Health Care Cost Trend Rates as of December 31 Health Care Costs Immediate Rate 7.28 % 7.93 % 7.55 % Ultimate Rate 4.75 % 4.75 % 4.75 % Year Ultimate Rate Reached 2026 2026 2025 Millions Effect of a 1% Increase in the Assumed Rate of Increase in Health Care Benefit Costs Total of Service Cost and Interest Cost $ 1 $ 13 $ 11 Postretirement Benefit Obligation $ 21 $ 240 $ 191 Effect of a 1% Decrease in the Assumed Rate of Increase in Health Care Benefit Costs Total of Service Cost and Interest Cost $ (1 ) $ (10 ) $ (9 ) Postretirement Benefit Obligation $ (20 ) $ (198 ) $ (160 ) Plan Assets The investments of pension and OPEB plans are held in a trust account by the Trustee and consist of an undivided interest in an investment account of the Master Trust. The investments in the pension and OPEB plans are measured at fair value within a hierarchy that prioritizes the inputs to fair value measurements into three levels. See Note 18. Fair Value Measurements for more information on fair value guidance. Use of the Master Trust permits the commingling of pension plan assets and OPEB plan assets for investment and administrative purposes. Although assets of the plans are commingled in the Master Trust, the Trustee maintains supporting records for the purpose of allocating the net gain or loss of the investment account to the respective participating plans. The net investment income of the investment assets is allocated by the Trustee to each participating plan based on the relationship of the interest of each plan to the total of the interests of the participating plans. As of December 31, 2018 , the pension plan interest and OPEB plan interest in such assets of the Master Trust were approximately 91% and 9% , respectively. The following tables present information about the investments measured at fair value on a recurring basis as of December 31, 2018 and 2017 , including the fair value measurements and the levels of inputs used in determining those fair values. Recurring Fair Value Measurements as of December 31, 2018 Quoted Market Prices for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Description Total (Level 1) (Level 2) (Level 3) Millions Cash Equivalents (A) $ 99 $ 88 $ 11 $ — Equity Securities Common Stock (B) 1,156 1,156 — — Commingled (C) 1,338 960 378 — Preferred Stock (B) 7 7 — — Other (D) 1 1 — — Debt Securities (E) U.S. Treasury 526 — 526 — Government—Other 302 — 302 — Corporate 948 — 948 — Subtotal Fair Value $ 4,377 $ 2,212 $ 2,165 $ — Measured at net asset value practical expedient Commingled—Equities (F) 1,208 Private Equity (G) 10 Total Fair Value (H) $ 5,595 Recurring Fair Value Measurements as of December 31, 2017 Quoted Market Prices for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Description Total (Level 1) (Level 2) (Level 3) Millions Cash Equivalents (A) $ 133 $ 117 $ 16 $ — Equity Securities Common Stock (B) 1,275 1,275 — — Commingled (C) 1,401 1,218 183 — Preferred Stock (B) 6 6 — — Debt Securities (E) U.S. Treasury 571 — 571 — Government—Other 272 — 272 — Corporate 963 — 963 — Subtotal Fair Value $ 4,621 $ 2,616 $ 2,005 $ — Measured at net asset value practical expedient Commingled—Equities (F) 1,675 Private Equity (G) 14 Total Fair Value (H) $ 6,310 (A) The Collective Investment Fund publishes a daily net asset value (NAV) which participants may use for daily redemptions without restrictions (Level 1). Certain temporary investments are valued using inputs such as time-to-maturity, coupon rate, quality rating and current yield (Level 2). (B) Common stocks and preferred stocks are measured using observable data in active markets and considered Level 1. (C) Commingled Funds that allow daily redemption at their daily published NAV without restrictions are classified as Level 1. Commingled Funds that publish daily NAV but with certain near-term redemption restrictions which prevent redemption at the published daily NAV are classified as Level 2. (D) Investment in a publicly traded limited partnership. (E) Debt securities include mainly investment grade corporate and municipal bonds, U.S. Treasury obligations and Federal Agency asset-backed securities with a wide range of maturities. These investments are valued using an evaluated pricing approach that varies by asset class and reflects observable market information such as the most recent exchange price or quoted bid for similar securities. Market-based standard inputs typically include benchmark yields, reported trades, broker/dealer quotes and issuer spreads or the most recent quotes for similar securities which are a Level 2 measure. (F) Certain commingled equity funds are not included in the fair value hierarchy as they are measured at fair value using the NAV per share (or its equivalent) practical expedient. These funds do not meet the definition of readily determinable fair value due to limitations in published NAV (last business day of the month) and include certain redemption restrictions ranging from one to fifteen days advance notice prior to redemption days and limitations on withdrawals over 25% of the total fund. The objectives of these funds are mainly tracking the S&P Index or achieving long-term growth through investment in foreign equity securities and the MSCI Emerging Markets Index. (G) Private equity investments primarily include various limited partnerships that invest in either operating companies through acquisitions or developing a portfolio of non-US distressed investments to maximize total return on capital. These investments are valued at NAV (or its equivalent) on an annual basis and have significant redemption restrictions preventing redemption until fund liquidation and limited ability to sell these investments. Fund liquidation is not expected to occur for several more years. These investments have been removed from the fair value hierarchy in accordance with the guidance on NAV practical expedient. (H) Excludes net receivables of $14 million and $13 million at December 31, 2018 and 2017 , respectively, which consist of interest, dividends and receivables and payables related to pending securities sales and purchases. The following table provides the percentage of fair value of total plan assets for each major category of plan assets held for the qualified pension and OPEB plans as of the measurement date, December 31: As of December 31, Investments 2018 2017 Equity Securities 66 % 69 % Debt Securities 32 29 Other Investments 2 2 Total Percentage 100 % 100 % PSEG utilizes forecasted returns, risk, and correlation of all asset classes in order to develop an efficient portfolio. PSEG’s latest asset/liability study indicates that a long-term target asset allocation of 70% equities and 30% fixed income is consistent with the funds’ financial objectives. Derivative financial instruments are used by the plans’ investment managers primarily to adjust the fixed income duration of the portfolio and hedge the currency risk component of foreign investments. The expected long-term rate of return on plan assets was 7.8% for 2018 and will be 7.8% for 2019 . This expected return was determined based on the study discussed above, including a premium for active management and considered the plans’ historical annualized rate of return since inception. Plan Contributions PSEG has no planned contributions to its pension plans in 2019 . PSEG plans to make discretionary contributions of $10 million into its OPEB plan during 2019 . Estimated Future Benefit Payments The following pension benefit and postretirement benefit payments are expected to be paid to plan participants. Year Pension Benefits Other Benefits Millions 2019 $ 345 $ 91 2020 341 95 2021 352 87 2022 364 88 2023 373 89 2024-2028 2,004 428 Total $ 3,779 $ 878 401(k) Plans PSEG sponsors two 401(k) plans, which are defined contribution retirement plans subject to the Employee Retirement Income Security Act (ERISA). Eligible represented employees of PSEG’s subsidiaries participate in the PSEG Employee Savings Plan (Savings Plan), while eligible non-represented employees of PSEG’s subsidiaries participate in the PSEG Thrift and Tax-Deferred Savings Plan (Thrift Plan). Eligible employees may contribute up to 50% of their compensation to these plans, not to exceed the Internal Revenue Service (IRS) maximums, including any catch-up contributions for those employees age 50 and above. PSEG matches 50% of such employee contributions up to 7% of pay for Savings Plan participants and up to 8% of pay for Thrift Plan participants. The amount paid for employer matching contributions to the plans for PSEG, PSE&G and Power are detailed as follows: Thrift Plan and Savings Plan Years Ended December 31, 2018 2017 2016 Millions PSE&G $ 26 $ 25 $ 24 Power 10 11 12 Other 5 5 5 Total Employer Matching Contributions $ 41 $ 41 $ 41 Servco Pension and OPEB At the direction of LIPA, effective January 1, 2014, Servco established benefit plans that provide substantially the same benefits to its employees as those previously provided by National Grid Electric Services LLC (NGES), the predecessor T&D system manager for LIPA. Since the vast majority of Servco’s employees had worked under NGES’ T&D operations services arrangement with LIPA, Servco’s plans provide certain of those employees with pension and OPEB vested credit for prior years’ services earned while working for NGES. The benefit plans cover all employees of Servco for current service. Under the OSA, all of these and any future employee benefit costs are to be funded by LIPA. See Note 5. Variable Interest Entity . These obligations, as well as the offsetting long-term receivable, are separately presented on the Consolidated Balance Sheet of PSEG. The following table provides a roll-forward of the changes in Servco’s benefit obligation and the fair value of its plan assets during the years ended December 31, 2018 and 2017 . It also provides the funded status of the plans and the amounts recognized and amounts not recognized on the Consolidated Balance Sheets at the end of both years. Pension Benefits Other Benefits 2018 2017 2018 2017 Millions Change in Benefit Obligation Benefit Obligation at Beginning of Year $ 320 $ 262 $ 542 $ 452 Service Cost 30 27 18 15 Interest Cost 12 11 20 19 Actuarial (Gain) Loss (38 ) 22 (73 ) 60 Gross Benefits Paid (3 ) (2 ) (6 ) (4 ) Plan Amendments — — — — Benefit Obligation at End of Year (A) $ 321 $ 320 $ 501 $ 542 Change in Plan Assets Fair Value of Assets at Beginning of Year $ 191 $ 134 $ — $ — Actual Return on Plan Assets (16 ) 24 — — Employer Contributions 40 35 6 4 Gross Benefits Paid (3 ) (2 ) (6 ) (4 ) Fair Value of Assets at End of Year $ 212 $ 191 $ — $ — Funded Status Funded Status (Plan Assets less Benefit Obligation) $ (109 ) $ (129 ) $ (501 ) $ (542 ) Additional Amounts Recognized in the Consolidated Balance Sheets Accrued Pension Costs of Servco $ (109 ) $ (129 ) N/A N/A OPEB Costs of Servco N/A N/A (501 ) (542 ) Amounts Recognized (B) $ (109 ) $ (129 ) $ (501 ) $ (542 ) (A) Represents projected benefit obligation for pension benefits and the accumulated postretirement benefit obligation for other benefits. The vested benefit obligation is the actuarial present value of the vested benefits to which the employee is currently entitled but based on the employee’s expected date of separation of retirement. (B) Amounts equal to the accrued pension and OPEB costs of Servco are offset in Long-Term Receivable of VIE on PSEG’s Consolidated Balance Sheets. Pension and OPEB costs of Servco are accounted for according to the OSA. Servco recognizes expenses for contributions to its pension plan trusts and for OPEB payments made to retirees. Operating Revenues are recognized for the reimbursement of these costs. The pension-related revenues and costs for 2018 , 2017 and 2016 were $40 million , $35 million and $28 million , respectively. Servco has contributed its entire planned contribution amount to its pension plan trusts during 2018 . The OPEB-related revenues earned and costs incurred were $6 million , $4 million and $2 million in 2018 , 2017 and 2016 , respectively. The following assumptions were used to determine the benefit obligations of Servco: Pension Benefits Other Benefits 2018 2017 2016 2018 2017 2016 Weighted-Average Assumptions Used to Determine Benefit Obligations as of December 31 Discount Rate 4.60 % 3.90 % 4.61 % 4.67 % 3.96 % 4.71 % Rate of Compensation Increase 3.25 % 3.25 % 3.25 % 3.25 % 3.25 % 3.25 % Assumed Health Care Cost Trend Rates as of December 31 Health Care Costs Immediate Rate 8.03 % 7.69 % 7.55 % Ultimate Rate 4.75 % 4.75 % 4.75 % Year Ultimate Rate Reached 2026 2026 2025 Millions Effect of a 1% Increase in the Assumed Rate of Increase in Health Care Benefit Costs Postretirement Benefit Obligation $ 108 $ 131 $ 97 Effect of a 1% Decrease in the Assumed Rate of Increase in Health Care Benefit Costs Postretirement Benefit Obligation $ (83 ) $ (99 ) $ (75 ) Plan Assets All the investments of Servco’s pension plans are held in a trust account by the Trustee and consist of an undivided interest in an investment account of the Master Trust. The investments in the pension are measured at fair value within a hierarchy that prioritizes the inputs to fair value measurements into three levels. See Note 18. Fair Value Measurements for more information on fair value guidance. The Actuary maintains supporting records for the purpose of allocating the net gain or loss of the investment account to the respective participating plans. The net investment income of the investment assets is allocated by the Actuary to each participating plan based on the relationship of the interest of each plan to the total of the interests of the participating plans. The following tables present information about Servco’s investments measured at fair value on a recurring basis as of December 31, 2018 and 2017 , including the fair value measurements and the levels of inputs used in determining those fair values. Recurring Fair Value Measurements as of December 31, 2018 Quoted Market Prices for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Description Total (Level 1) (Level 2) (Level 3) Millions Commingled Equities (A) $ 141 $ — $ 141 $ — Commingled Bonds (A) 71 — 71 — Total $ 212 $ — $ 212 $ — Recurring Fair Value Measurements as of December 31, 2017 Quoted Market Prices for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Description Total (Level 1) (Level 2) (Level 3) Millions Commingled Equities (A) $ 137 $ — $ 137 $ — Commingled Bonds (A) 54 — 54 — Total $ 191 $ — $ 191 $ — (A) Investments in commingled equity and bond funds have a readily determinable fair value as they publish a daily NAV available to investors which is the basis for current transactions and contain certain redemption restrictions requiring advance notice of one to two days for withdrawals (Level 2). The following table provides the percentage of fair value of total plan assets for each major category of plan assets held for the qualified pension and OPEB plans of Servco as of the measurement date, December 31: As of December 31, Investments 2018 2017 Equity Securities 67 % 72 % Debt Securities 33 28 Total Percentage 100 % 100 % Servco utilizes forecasted returns, risk, and correlation of all asset classes in order to develop an efficient portfolio. The results from Servco’s latest asset/liability study indicated that a long-term target asset allocation of 70% equities and 30% fixed income is consistent with the funds’ financial objectives. The expected long-term rate of return on plan assets was 7.6% for 2018 and will be 7.6% for 2019 . This expected return was determined based on the study discussed above, including a premium for active management. Plan Contributions Servco plans to contribute $28 million into its pension plan during 2019 . Estimated Future Benefit Payments The following pension benefit and postretirement benefit payments are expected to be paid to Servco’s plan participants: Year Pension Benefits Other Benefits Millions 2019 $ 4 $ 6 2020 6 8 2021 7 10 2022 9 12 2023 11 14 2024-2028 91 99 Total $ 128 $ 149 Servco 401(k) Plans Servco sponsors two 401(k) plans, which are defined contribution retirement plans subject to ERISA. Eligible non-represented employees of Servco participate in the Long Island Electric Utility Servco LLC Incentive Thrift Plan I (Thrift Plan I), and eligible represented employees of Servco participate in the Long Island Electric Utility Servco LLC Incentive Thrift Plan II (Thrift Plan II). Participants in the plans may contribute up to 50% of their eligible compensation to these plans, not to exceed the IRS maximums, including any catch-up contributions for those employees age 50 and above. Servco does not provide an employer match or core contribution for employees in Thrift Plan II. For employees in Thrift Plan I, Servco matches 50% of such employee contributions up to 8% of eligible compensation and provides core contributions (based on years of service and age) to employees who do not participate in Servco’s Retirement Income Plan. The amounts expensed by Servco for employer matching contributions for the years ended December 31, 2018 , 2017 and 2016 were $7 million , $6 million and $5 million , respectively, and pursuant to the OSA, Servco recognizes Operating Revenues for the reimbursement of these costs.
PSE&G [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension, OPEB and Savings Plans	Pension, Other Postretirement Benefits (OPEB) and Savings Plans PSEG sponsors qualified and nonqualified pension plans and OPEB plans covering PSEG’s and its participating affiliates’ current and former employees who meet certain eligibility criteria. Eligible employees participate in non-contributory pension and OPEB plans sponsored by PSEG and administered by Services. In addition, represented and nonrepresented employees are eligible for participation in PSEG’s two defined contribution plans described below. PSEG, PSE&G and Power are required to record the under or over funded positions of their defined benefit pension and OPEB plans on their respective balance sheets. Such funding positions of each PSEG company are required to be measured as of the date of its respective year-end Consolidated Balance Sheets. For underfunded plans, the liability is equal to the difference between the plan’s benefit obligation and the fair value of plan assets. For defined benefit pension plans, the benefit obligation is the projected benefit obligation. For OPEB plans, the benefit obligation is the accumulated postretirement benefit obligation. In addition, GAAP requires that the total unrecognized costs for defined benefit pension and OPEB plans be recorded as an after-tax charge to Accumulated Other Comprehensive Income (Loss), a separate component of Stockholders’ Equity. However, for PSE&G, because the amortization of the unrecognized costs is being collected from customers, the accumulated unrecognized costs are recorded as a Regulatory Asset. The unrecognized costs represent actuarial gains or losses and prior service costs which had not been expensed. For PSE&G, the Regulatory Asset is amortized and recorded as net periodic pension cost in the Consolidated Statements of Operations. For Power, the charge to Accumulated Other Comprehensive Income (Loss) is amortized and recorded as net periodic pension cost in the Consolidated Statements of Operations. In December 2018, PSEG amended certain provisions of its OPEB plans applicable to all current and future Medicare-eligible retirees and spouses who receive or will receive subsidized healthcare from PSEG. Effective January 1, 2021, the PSEG-sponsored Medicare-eligible plans will be replaced by a Medicare private exchange. For each Medicare-eligible retiree and spouse, PSEG will provide annual credits to a Health Reimbursement Arrangement, which can be used to pay for medical, prescription drug, and dental plan premiums, as well as certain out-of-pocket costs. The amendment resulted in a $559 million reduction in PSEG’s OPEB obligation as of December 31, 2018 . Amounts for Servco are not included in any of the following pension and OPEB benefit information for PSEG and its affiliates but rather are separately disclosed later in this note. The following table provides a roll-forward of the changes in the benefit obligation and the fair value of plan assets during each of the two years in the periods ended December 31, 2018 and 2017 . It also provides the funded status of the plans and the amounts recognized and amounts not recognized on the Consolidated Balance Sheets at the end of both years. Pension Benefits Other Benefits 2018 2017 2018 2017 Millions Change in Benefit Obligation Benefit Obligation at Beginning of Year (A) $ 6,359 $ 5,772 $ 1,976 $ 1,754 Service Cost 130 114 18 17 Interest Cost 208 204 66 63 Actuarial (Gain) Loss (460 ) 564 (222 ) 199 Gross Benefits Paid (316 ) (295 ) (76 ) (57 ) Plan Amendments — — (559 ) — Benefit Obligation at End of Year (A) $ 5,921 $ 6,359 $ 1,203 $ 1,976 Change in Plan Assets Fair Value of Assets at Beginning of Year $ 5,812 $ 5,193 $ 511 $ 420 Actual Return on Plan Assets (388 ) 903 (36 ) 77 Employer Contributions 12 11 89 71 Gross Benefits Paid (316 ) (295 ) (76 ) (57 ) Fair Value of Assets at End of Year $ 5,120 $ 5,812 $ 488 $ 511 Funded Status Funded Status (Plan Assets less Benefit Obligation) $ (801 ) $ (547 ) $ (715 ) $ (1,465 ) Additional Amounts Recognized in the Consolidated Balance Sheets Current Accrued Benefit Cost (10 ) (10 ) (11 ) (10 ) Noncurrent Accrued Benefit Cost (791 ) (537 ) (704 ) (1,455 ) Amounts Recognized $ (801 ) $ (547 ) $ (715 ) $ (1,465 ) Additional Amounts Recognized in Accumulated Other Comprehensive Income (Loss), Regulated Assets and Deferred Assets (B) Prior Service Cost $ (28 ) $ (46 ) $ (561 ) $ (3 ) Net Actuarial Loss 2,005 1,721 420 629 Total $ 1,977 $ 1,675 $ (141 ) $ 626 (A) Represents projected benefit obligation for pension benefits and the accumulated postretirement benefit obligation for other benefits. The vested benefit obligation is the actuarial present value of the vested benefits to which the employee is currently entitled but based on the employee’s expected date of separation of retirement. (B) Includes $ 619 million ($ 360 million , after-tax) and $ 683 million ($ 406 million , after-tax) in Accumulated Other Comprehensive Loss related to Pension and OPEB as of December 31, 2018 and 2017 , respectively. Also includes Regulatory Assets of $1,090 million and Deferred Assets of $127 million as of December 31, 2018 and Regulatory Assets of $1,485 million and Deferred Assets of $133 million as of December 31, 2017 . The pension benefits table above provides information relating to the funded status of the qualified and nonqualified pension and OPEB plans on an aggregate basis. As of December 31, 2018 , PSEG had funded approximately 86% of its projected benefit obligation. This percentage does not include $ 224 million of assets in the Rabbi Trust as of December 31, 2018 which were used partially to fund the nonqualified pension plans. As of December 31, 2018 , the nonqualified pension plans included in the projected benefit obligation in the above table were $156 million . Accumulated Benefit Obligation The accumulated benefit obligation for all PSEG’s defined benefit pension plans was $ 5.7 billion as of December 31, 2018 and $ 6.1 billion as of December 31, 2017 . The following table provides the components of net periodic benefit cost relating to all qualified and nonqualified pension and OPEB plans on an aggregate basis for PSEG, excluding Servco for the years ended December 31, 2018 , 2017 and 2016 . Amounts shown do not reflect the impacts of capitalization and co-owner allocations. Effective with the adoption of ASU 2017-07 on January 1, 2018, only the service cost component is eligible for capitalization, when applicable. For additional information, see Note 2. Recent Accounting Standards . Pension Benefits Years Ended December 31, Other Benefits Years Ended December 31, 2018 2017 2016 2018 2017 2016 Millions Components of Net Periodic Benefit (Credits) Costs Service Cost (included in O&M Expense) $ 130 $ 114 $ 109 $ 18 $ 17 $ 17 Non-Service Components of Pension and OPEB (Credits) Costs Interest Cost 208 204 202 66 63 59 Expected Return on Plan Assets (441 ) (394 ) (394 ) (41 ) (34 ) (31 ) Amortization of Net Prior Service Credit (18 ) (18 ) (19 ) (1 ) (11 ) (14 ) Actuarial Loss 85 97 158 64 51 40 Non-Service Components of Pension and OPEB (Credits) Costs (166 ) (111 ) (53 ) 88 69 54 Total Benefit (Credits) Costs $ (36 ) $ 3 $ 56 $ 106 $ 86 $ 71 Pension costs and OPEB costs for PSEG, PSE&G and Power are detailed as follows: Pension Benefits Years Ended December 31, Other Benefits Years Ended December 31, 2018 2017 2016 2018 2017 2016 Millions PSE&G $ (31 ) $ (4 ) $ 29 $ 68 $ 54 $ 43 Power (9 ) 1 16 32 27 23 Other 4 6 11 6 5 5 Total Benefit (Credits) Costs $ (36 ) $ 3 $ 56 $ 106 $ 86 $ 71 The following table provides the pre-tax changes recognized in Accumulated Other Comprehensive Income (Loss), Regulatory Assets and Deferred Assets: Pension OPEB 2018 2017 2018 2017 Millions Net Actuarial (Gain) Loss in Current Period $ 369 $ 55 $ (145 ) $ 156 Amortization of Net Actuarial Gain (Loss) (85 ) (97 ) (64 ) (50 ) Prior Service Cost (Credit) in current period — — (559 ) — Amortization of Prior Service Credit 18 18 1 11 Total $ 302 $ (24 ) $ (767 ) $ 117 Amounts that are expected to be amortized from Accumulated Other Comprehensive Loss, Regulatory Assets and Deferred Assets into Net Periodic Benefit Cost in 2019 are as follows: Pension Benefits Other Benefits 2019 2019 Millions Actuarial Loss $ 107 $ 50 Prior Service Credit $ (18 ) $ (128 ) The following assumptions were used to determine the benefit obligations and net periodic benefit costs: Pension Benefits Other Benefits 2018 2017 2016 2018 2017 2016 Weighted-Average Assumptions Used to Determine Benefit Obligations as of December 31 Discount Rate 4.41 % 3.73 % 4.29 % 4.31 % 3.76 % 4.37 % Rate of Compensation Increase 3.90 % 3.90 % 3.61 % 3.90 % 3.90 % 3.61 % Weighted-Average Assumptions Used to Determine Net Periodic Benefit Cost for Years Ended December 31 Discount Rate 3.73 % 4.29 % 4.54 % 3.76 % 4.37 % 4.58 % Service Cost Interest Rate 3.88 % 4.53 % 4.81 % 3.90 % 4.64 % 4.87 % Interest Cost Interest Rate 3.35 % 3.63 % 3.75 % 3.39 % 3.69 % 3.76 % Expected Return on Plan Assets 7.80 % 7.80 % 8.00 % 7.80 % 7.80 % 8.00 % Rate of Compensation Increase 3.90 % 3.61 % 3.61 % 3.90 % 3.61 % 3.61 % Assumed Health Care Cost Trend Rates as of December 31 Health Care Costs Immediate Rate 7.28 % 7.93 % 7.55 % Ultimate Rate 4.75 % 4.75 % 4.75 % Year Ultimate Rate Reached 2026 2026 2025 Millions Effect of a 1% Increase in the Assumed Rate of Increase in Health Care Benefit Costs Total of Service Cost and Interest Cost $ 1 $ 13 $ 11 Postretirement Benefit Obligation $ 21 $ 240 $ 191 Effect of a 1% Decrease in the Assumed Rate of Increase in Health Care Benefit Costs Total of Service Cost and Interest Cost $ (1 ) $ (10 ) $ (9 ) Postretirement Benefit Obligation $ (20 ) $ (198 ) $ (160 ) Plan Assets The investments of pension and OPEB plans are held in a trust account by the Trustee and consist of an undivided interest in an investment account of the Master Trust. The investments in the pension and OPEB plans are measured at fair value within a hierarchy that prioritizes the inputs to fair value measurements into three levels. See Note 18. Fair Value Measurements for more information on fair value guidance. Use of the Master Trust permits the commingling of pension plan assets and OPEB plan assets for investment and administrative purposes. Although assets of the plans are commingled in the Master Trust, the Trustee maintains supporting records for the purpose of allocating the net gain or loss of the investment account to the respective participating plans. The net investment income of the investment assets is allocated by the Trustee to each participating plan based on the relationship of the interest of each plan to the total of the interests of the participating plans. As of December 31, 2018 , the pension plan interest and OPEB plan interest in such assets of the Master Trust were approximately 91% and 9% , respectively. The following tables present information about the investments measured at fair value on a recurring basis as of December 31, 2018 and 2017 , including the fair value measurements and the levels of inputs used in determining those fair values. Recurring Fair Value Measurements as of December 31, 2018 Quoted Market Prices for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Description Total (Level 1) (Level 2) (Level 3) Millions Cash Equivalents (A) $ 99 $ 88 $ 11 $ — Equity Securities Common Stock (B) 1,156 1,156 — — Commingled (C) 1,338 960 378 — Preferred Stock (B) 7 7 — — Other (D) 1 1 — — Debt Securities (E) U.S. Treasury 526 — 526 — Government—Other 302 — 302 — Corporate 948 — 948 — Subtotal Fair Value $ 4,377 $ 2,212 $ 2,165 $ — Measured at net asset value practical expedient Commingled—Equities (F) 1,208 Private Equity (G) 10 Total Fair Value (H) $ 5,595 Recurring Fair Value Measurements as of December 31, 2017 Quoted Market Prices for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Description Total (Level 1) (Level 2) (Level 3) Millions Cash Equivalents (A) $ 133 $ 117 $ 16 $ — Equity Securities Common Stock (B) 1,275 1,275 — — Commingled (C) 1,401 1,218 183 — Preferred Stock (B) 6 6 — — Debt Securities (E) U.S. Treasury 571 — 571 — Government—Other 272 — 272 — Corporate 963 — 963 — Subtotal Fair Value $ 4,621 $ 2,616 $ 2,005 $ — Measured at net asset value practical expedient Commingled—Equities (F) 1,675 Private Equity (G) 14 Total Fair Value (H) $ 6,310 (A) The Collective Investment Fund publishes a daily net asset value (NAV) which participants may use for daily redemptions without restrictions (Level 1). Certain temporary investments are valued using inputs such as time-to-maturity, coupon rate, quality rating and current yield (Level 2). (B) Common stocks and preferred stocks are measured using observable data in active markets and considered Level 1. (C) Commingled Funds that allow daily redemption at their daily published NAV without restrictions are classified as Level 1. Commingled Funds that publish daily NAV but with certain near-term redemption restrictions which prevent redemption at the published daily NAV are classified as Level 2. (D) Investment in a publicly traded limited partnership. (E) Debt securities include mainly investment grade corporate and municipal bonds, U.S. Treasury obligations and Federal Agency asset-backed securities with a wide range of maturities. These investments are valued using an evaluated pricing approach that varies by asset class and reflects observable market information such as the most recent exchange price or quoted bid for similar securities. Market-based standard inputs typically include benchmark yields, reported trades, broker/dealer quotes and issuer spreads or the most recent quotes for similar securities which are a Level 2 measure. (F) Certain commingled equity funds are not included in the fair value hierarchy as they are measured at fair value using the NAV per share (or its equivalent) practical expedient. These funds do not meet the definition of readily determinable fair value due to limitations in published NAV (last business day of the month) and include certain redemption restrictions ranging from one to fifteen days advance notice prior to redemption days and limitations on withdrawals over 25% of the total fund. The objectives of these funds are mainly tracking the S&P Index or achieving long-term growth through investment in foreign equity securities and the MSCI Emerging Markets Index. (G) Private equity investments primarily include various limited partnerships that invest in either operating companies through acquisitions or developing a portfolio of non-US distressed investments to maximize total return on capital. These investments are valued at NAV (or its equivalent) on an annual basis and have significant redemption restrictions preventing redemption until fund liquidation and limited ability to sell these investments. Fund liquidation is not expected to occur for several more years. These investments have been removed from the fair value hierarchy in accordance with the guidance on NAV practical expedient. (H) Excludes net receivables of $14 million and $13 million at December 31, 2018 and 2017 , respectively, which consist of interest, dividends and receivables and payables related to pending securities sales and purchases. The following table provides the percentage of fair value of total plan assets for each major category of plan assets held for the qualified pension and OPEB plans as of the measurement date, December 31: As of December 31, Investments 2018 2017 Equity Securities 66 % 69 % Debt Securities 32 29 Other Investments 2 2 Total Percentage 100 % 100 % PSEG utilizes forecasted returns, risk, and correlation of all asset classes in order to develop an efficient portfolio. PSEG’s latest asset/liability study indicates that a long-term target asset allocation of 70% equities and 30% fixed income is consistent with the funds’ financial objectives. Derivative financial instruments are used by the plans’ investment managers primarily to adjust the fixed income duration of the portfolio and hedge the currency risk component of foreign investments. The expected long-term rate of return on plan assets was 7.8% for 2018 and will be 7.8% for 2019 . This expected return was determined based on the study discussed above, including a premium for active management and considered the plans’ historical annualized rate of return since inception. Plan Contributions PSEG has no planned contributions to its pension plans in 2019 . PSEG plans to make discretionary contributions of $10 million into its OPEB plan during 2019 . Estimated Future Benefit Payments The following pension benefit and postretirement benefit payments are expected to be paid to plan participants. Year Pension Benefits Other Benefits Millions 2019 $ 345 $ 91 2020 341 95 2021 352 87 2022 364 88 2023 373 89 2024-2028 2,004 428 Total $ 3,779 $ 878 401(k) Plans PSEG sponsors two 401(k) plans, which are defined contribution retirement plans subject to the Employee Retirement Income Security Act (ERISA). Eligible represented employees of PSEG’s subsidiaries participate in the PSEG Employee Savings Plan (Savings Plan), while eligible non-represented employees of PSEG’s subsidiaries participate in the PSEG Thrift and Tax-Deferred Savings Plan (Thrift Plan). Eligible employees may contribute up to 50% of their compensation to these plans, not to exceed the Internal Revenue Service (IRS) maximums, including any catch-up contributions for those employees age 50 and above. PSEG matches 50% of such employee contributions up to 7% of pay for Savings Plan participants and up to 8% of pay for Thrift Plan participants. The amount paid for employer matching contributions to the plans for PSEG, PSE&G and Power are detailed as follows: Thrift Plan and Savings Plan Years Ended December 31, 2018 2017 2016 Millions PSE&G $ 26 $ 25 $ 24 Power 10 11 12 Other 5 5 5 Total Employer Matching Contributions $ 41 $ 41 $ 41 Servco Pension and OPEB At the direction of LIPA, effective January 1, 2014, Servco established benefit plans that provide substantially the same benefits to its employees as those previously provided by National Grid Electric Services LLC (NGES), the predecessor T&D system manager for LIPA. Since the vast majority of Servco’s employees had worked under NGES’ T&D operations services arrangement with LIPA, Servco’s plans provide certain of those employees with pension and OPEB vested credit for prior years’ services earned while working for NGES. The benefit plans cover all employees of Servco for current service. Under the OSA, all of these and any future employee benefit costs are to be funded by LIPA. See Note 5. Variable Interest Entity . These obligations, as well as the offsetting long-term receivable, are separately presented on the Consolidated Balance Sheet of PSEG. The following table provides a roll-forward of the changes in Servco’s benefit obligation and the fair value of its plan assets during the years ended December 31, 2018 and 2017 . It also provides the funded status of the plans and the amounts recognized and amounts not recognized on the Consolidated Balance Sheets at the end of both years. Pension Benefits Other Benefits 2018 2017 2018 2017 Millions Change in Benefit Obligation Benefit Obligation at Beginning of Year $ 320 $ 262 $ 542 $ 452 Service Cost 30 27 18 15 Interest Cost 12 11 20 19 Actuarial (Gain) Loss (38 ) 22 (73 ) 60 Gross Benefits Paid (3 ) (2 ) (6 ) (4 ) Plan Amendments — — — — Benefit Obligation at End of Year (A) $ 321 $ 320 $ 501 $ 542 Change in Plan Assets Fair Value of Assets at Beginning of Year $ 191 $ 134 $ — $ — Actual Return on Plan Assets (16 ) 24 — — Employer Contributions 40 35 6 4 Gross Benefits Paid (3 ) (2 ) (6 ) (4 ) Fair Value of Assets at End of Year $ 212 $ 191 $ — $ — Funded Status Funded Status (Plan Assets less Benefit Obligation) $ (109 ) $ (129 ) $ (501 ) $ (542 ) Additional Amounts Recognized in the Consolidated Balance Sheets Accrued Pension Costs of Servco $ (109 ) $ (129 ) N/A N/A OPEB Costs of Servco N/A N/A (501 ) (542 ) Amounts Recognized (B) $ (109 ) $ (129 ) $ (501 ) $ (542 ) (A) Represents projected benefit obligation for pension benefits and the accumulated postretirement benefit obligation for other benefits. The vested benefit obligation is the actuarial present value of the vested benefits to which the employee is currently entitled but based on the employee’s expected date of separation of retirement. (B) Amounts equal to the accrued pension and OPEB costs of Servco are offset in Long-Term Receivable of VIE on PSEG’s Consolidated Balance Sheets. Pension and OPEB costs of Servco are accounted for according to the OSA. Servco recognizes expenses for contributions to its pension plan trusts and for OPEB payments made to retirees. Operating Revenues are recognized for the reimbursement of these costs. The pension-related revenues and costs for 2018 , 2017 and 2016 were $40 million , $35 million and $28 million , respectively. Servco has contributed its entire planned contribution amount to its pension plan trusts during 2018 . The OPEB-related revenues earned and costs incurred were $6 million , $4 million and $2 million in 2018 , 2017 and 2016 , respectively. The following assumptions were used to determine the benefit obligations of Servco: Pension Benefits Other Benefits 2018 2017 2016 2018 2017 2016 Weighted-Average Assumptions Used to Determine Benefit Obligations as of December 31 Discount Rate 4.60 % 3.90 % 4.61 % 4.67 % 3.96 % 4.71 % Rate of Compensation Increase 3.25 % 3.25 % 3.25 % 3.25 % 3.25 % 3.25 % Assumed Health Care Cost Trend Rates as of December 31 Health Care Costs Immediate Rate 8.03 % 7.69 % 7.55 % Ultimate Rate 4.75 % 4.75 % 4.75 % Year Ultimate Rate Reached 2026 2026 2025 Millions Effect of a 1% Increase in the Assumed Rate of Increase in Health Care Benefit Costs Postretirement Benefit Obligation $ 108 $ 131 $ 97 Effect of a 1% Decrease in the Assumed Rate of Increase in Health Care Benefit Costs Postretirement Benefit Obligation $ (83 ) $ (99 ) $ (75 ) Plan Assets All the investments of Servco’s pension plans are held in a trust account by the Trustee and consist of an undivided interest in an investment account of the Master Trust. The investments in the pension are measured at fair value within a hierarchy that prioritizes the inputs to fair value measurements into three levels. See Note 18. Fair Value Measurements for more information on fair value guidance. The Actuary maintains supporting records for the purpose of allocating the net gain or loss of the investment account to the respective participating plans. The net investment income of the investment assets is allocated by the Actuary to each participating plan based on the relationship of the interest of each plan to the total of the interests of the participating plans. The following tables present information about Servco’s investments measured at fair value on a recurring basis as of December 31, 2018 and 2017 , including the fair value measurements and the levels of inputs used in determining those fair values. Recurring Fair Value Measurements as of December 31, 2018 Quoted Market Prices for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Description Total (Level 1) (Level 2) (Level 3) Millions Commingled Equities (A) $ 141 $ — $ 141 $ — Commingled Bonds (A) 71 — 71 — Total $ 212 $ — $ 212 $ — Recurring Fair Value Measurements as of December 31, 2017 Quoted Market Prices for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Description Total (Level 1) (Level 2) (Level 3) Millions Commingled Equities (A) $ 137 $ — $ 137 $ — Commingled Bonds (A) 54 — 54 — Total $ 191 $ — $ 191 $ — (A) Investments in commingled equity and bond funds have a readily determinable fair value as they publish a daily NAV available to investors which is the basis for current transactions and contain certain redemption restrictions requiring advance notice of one to two days for withdrawals (Level 2). The following table provides the percentage of fair value of total plan assets for each major category of plan assets held for the qualified pension and OPEB plans of Servco as of the measurement date, December 31: As of December 31, Investments 2018 2017 Equity Securities 67 % 72 % Debt Securities 33 28 Total Percentage 100 % 100 % Servco utilizes forecasted returns, risk, and correlation of all asset classes in order to develop an efficient portfolio. The results from Servco’s latest asset/liability study indicated that a long-term target asset allocation of 70% equities and 30% fixed income is consistent with the funds’ financial objectives. The expected long-term rate of return on plan assets was 7.6% for 2018 and will be 7.6% for 2019 . This expected return was determined based on the study discussed above, including a premium for active management. Plan Contributions Servco plans to contribute $28 million into its pension plan during 2019 . Estimated Future Benefit Payments The following pension benefit and postretirement benefit payments are expected to be paid to Servco’s plan participants: Year Pension Benefits Other Benefits Millions 2019 $ 4 $ 6 2020 6 8 2021 7 10 2022 9 12 2023 11 14 2024-2028 91 99 Total $ 128 $ 149 Servco 401(k) Plans Servco sponsors two 401(k) plans, which are defined contribution retirement plans subject to ERISA. Eligible non-represented employees of Servco participate in the Long Island Electric Utility Servco LLC Incentive Thrift Plan I (Thrift Plan I), and eligible represented employees of Servco participate in the Long Island Electric Utility Servco LLC Incentive Thrift Plan II (Thrift Plan II). Participants in the plans may contribute up to 50% of their eligible compensation to these plans, not to exceed the IRS maximums, including any catch-up contributions for those employees age 50 and above. Servco does not provide an employer match or core contribution for employees in Thrift Plan II. For employees in Thrift Plan I, Servco matches 50% of such employee contributions up to 8% of eligible compensation and provides core contributions (based on years of service and age) to employees who do not participate in Servco’s Retirement Income Plan. The amounts expensed by Servco for employer matching contributions for the years ended December 31, 2018 , 2017 and 2016 were $7 million , $6 million and $5 million , respectively, and pursuant to the OSA, Servco recognizes Operating Revenues for the reimbursement of these costs.
Power [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension, OPEB and Savings Plans	Pension, Other Postretirement Benefits (OPEB) and Savings Plans PSEG sponsors qualified and nonqualified pension plans and OPEB plans covering PSEG’s and its participating affiliates’ current and former employees who meet certain eligibility criteria. Eligible employees participate in non-contributory pension and OPEB plans sponsored by PSEG and administered by Services. In addition, represented and nonrepresented employees are eligible for participation in PSEG’s two defined contribution plans described below. PSEG, PSE&G and Power are required to record the under or over funded positions of their defined benefit pension and OPEB plans on their respective balance sheets. Such funding positions of each PSEG company are required to be measured as of the date of its respective year-end Consolidated Balance Sheets. For underfunded plans, the liability is equal to the difference between the plan’s benefit obligation and the fair value of plan assets. For defined benefit pension plans, the benefit obligation is the projected benefit obligation. For OPEB plans, the benefit obligation is the accumulated postretirement benefit obligation. In addition, GAAP requires that the total unrecognized costs for defined benefit pension and OPEB plans be recorded as an after-tax charge to Accumulated Other Comprehensive Income (Loss), a separate component of Stockholders’ Equity. However, for PSE&G, because the amortization of the unrecognized costs is being collected from customers, the accumulated unrecognized costs are recorded as a Regulatory Asset. The unrecognized costs represent actuarial gains or losses and prior service costs which had not been expensed. For PSE&G, the Regulatory Asset is amortized and recorded as net periodic pension cost in the Consolidated Statements of Operations. For Power, the charge to Accumulated Other Comprehensive Income (Loss) is amortized and recorded as net periodic pension cost in the Consolidated Statements of Operations. In December 2018, PSEG amended certain provisions of its OPEB plans applicable to all current and future Medicare-eligible retirees and spouses who receive or will receive subsidized healthcare from PSEG. Effective January 1, 2021, the PSEG-sponsored Medicare-eligible plans will be replaced by a Medicare private exchange. For each Medicare-eligible retiree and spouse, PSEG will provide annual credits to a Health Reimbursement Arrangement, which can be used to pay for medical, prescription drug, and dental plan premiums, as well as certain out-of-pocket costs. The amendment resulted in a $559 million reduction in PSEG’s OPEB obligation as of December 31, 2018 . Amounts for Servco are not included in any of the following pension and OPEB benefit information for PSEG and its affiliates but rather are separately disclosed later in this note. The following table provides a roll-forward of the changes in the benefit obligation and the fair value of plan assets during each of the two years in the periods ended December 31, 2018 and 2017 . It also provides the funded status of the plans and the amounts recognized and amounts not recognized on the Consolidated Balance Sheets at the end of both years. Pension Benefits Other Benefits 2018 2017 2018 2017 Millions Change in Benefit Obligation Benefit Obligation at Beginning of Year (A) $ 6,359 $ 5,772 $ 1,976 $ 1,754 Service Cost 130 114 18 17 Interest Cost 208 204 66 63 Actuarial (Gain) Loss (460 ) 564 (222 ) 199 Gross Benefits Paid (316 ) (295 ) (76 ) (57 ) Plan Amendments — — (559 ) — Benefit Obligation at End of Year (A) $ 5,921 $ 6,359 $ 1,203 $ 1,976 Change in Plan Assets Fair Value of Assets at Beginning of Year $ 5,812 $ 5,193 $ 511 $ 420 Actual Return on Plan Assets (388 ) 903 (36 ) 77 Employer Contributions 12 11 89 71 Gross Benefits Paid (316 ) (295 ) (76 ) (57 ) Fair Value of Assets at End of Year $ 5,120 $ 5,812 $ 488 $ 511 Funded Status Funded Status (Plan Assets less Benefit Obligation) $ (801 ) $ (547 ) $ (715 ) $ (1,465 ) Additional Amounts Recognized in the Consolidated Balance Sheets Current Accrued Benefit Cost (10 ) (10 ) (11 ) (10 ) Noncurrent Accrued Benefit Cost (791 ) (537 ) (704 ) (1,455 ) Amounts Recognized $ (801 ) $ (547 ) $ (715 ) $ (1,465 ) Additional Amounts Recognized in Accumulated Other Comprehensive Income (Loss), Regulated Assets and Deferred Assets (B) Prior Service Cost $ (28 ) $ (46 ) $ (561 ) $ (3 ) Net Actuarial Loss 2,005 1,721 420 629 Total $ 1,977 $ 1,675 $ (141 ) $ 626 (A) Represents projected benefit obligation for pension benefits and the accumulated postretirement benefit obligation for other benefits. The vested benefit obligation is the actuarial present value of the vested benefits to which the employee is currently entitled but based on the employee’s expected date of separation of retirement. (B) Includes $ 619 million ($ 360 million , after-tax) and $ 683 million ($ 406 million , after-tax) in Accumulated Other Comprehensive Loss related to Pension and OPEB as of December 31, 2018 and 2017 , respectively. Also includes Regulatory Assets of $1,090 million and Deferred Assets of $127 million as of December 31, 2018 and Regulatory Assets of $1,485 million and Deferred Assets of $133 million as of December 31, 2017 . The pension benefits table above provides information relating to the funded status of the qualified and nonqualified pension and OPEB plans on an aggregate basis. As of December 31, 2018 , PSEG had funded approximately 86% of its projected benefit obligation. This percentage does not include $ 224 million of assets in the Rabbi Trust as of December 31, 2018 which were used partially to fund the nonqualified pension plans. As of December 31, 2018 , the nonqualified pension plans included in the projected benefit obligation in the above table were $156 million . Accumulated Benefit Obligation The accumulated benefit obligation for all PSEG’s defined benefit pension plans was $ 5.7 billion as of December 31, 2018 and $ 6.1 billion as of December 31, 2017 . The following table provides the components of net periodic benefit cost relating to all qualified and nonqualified pension and OPEB plans on an aggregate basis for PSEG, excluding Servco for the years ended December 31, 2018 , 2017 and 2016 . Amounts shown do not reflect the impacts of capitalization and co-owner allocations. Effective with the adoption of ASU 2017-07 on January 1, 2018, only the service cost component is eligible for capitalization, when applicable. For additional information, see Note 2. Recent Accounting Standards . Pension Benefits Years Ended December 31, Other Benefits Years Ended December 31, 2018 2017 2016 2018 2017 2016 Millions Components of Net Periodic Benefit (Credits) Costs Service Cost (included in O&M Expense) $ 130 $ 114 $ 109 $ 18 $ 17 $ 17 Non-Service Components of Pension and OPEB (Credits) Costs Interest Cost 208 204 202 66 63 59 Expected Return on Plan Assets (441 ) (394 ) (394 ) (41 ) (34 ) (31 ) Amortization of Net Prior Service Credit (18 ) (18 ) (19 ) (1 ) (11 ) (14 ) Actuarial Loss 85 97 158 64 51 40 Non-Service Components of Pension and OPEB (Credits) Costs (166 ) (111 ) (53 ) 88 69 54 Total Benefit (Credits) Costs $ (36 ) $ 3 $ 56 $ 106 $ 86 $ 71 Pension costs and OPEB costs for PSEG, PSE&G and Power are detailed as follows: Pension Benefits Years Ended December 31, Other Benefits Years Ended December 31, 2018 2017 2016 2018 2017 2016 Millions PSE&G $ (31 ) $ (4 ) $ 29 $ 68 $ 54 $ 43 Power (9 ) 1 16 32 27 23 Other 4 6 11 6 5 5 Total Benefit (Credits) Costs $ (36 ) $ 3 $ 56 $ 106 $ 86 $ 71 The following table provides the pre-tax changes recognized in Accumulated Other Comprehensive Income (Loss), Regulatory Assets and Deferred Assets: Pension OPEB 2018 2017 2018 2017 Millions Net Actuarial (Gain) Loss in Current Period $ 369 $ 55 $ (145 ) $ 156 Amortization of Net Actuarial Gain (Loss) (85 ) (97 ) (64 ) (50 ) Prior Service Cost (Credit) in current period — — (559 ) — Amortization of Prior Service Credit 18 18 1 11 Total $ 302 $ (24 ) $ (767 ) $ 117 Amounts that are expected to be amortized from Accumulated Other Comprehensive Loss, Regulatory Assets and Deferred Assets into Net Periodic Benefit Cost in 2019 are as follows: Pension Benefits Other Benefits 2019 2019 Millions Actuarial Loss $ 107 $ 50 Prior Service Credit $ (18 ) $ (128 ) The following assumptions were used to determine the benefit obligations and net periodic benefit costs: Pension Benefits Other Benefits 2018 2017 2016 2018 2017 2016 Weighted-Average Assumptions Used to Determine Benefit Obligations as of December 31 Discount Rate 4.41 % 3.73 % 4.29 % 4.31 % 3.76 % 4.37 % Rate of Compensation Increase 3.90 % 3.90 % 3.61 % 3.90 % 3.90 % 3.61 % Weighted-Average Assumptions Used to Determine Net Periodic Benefit Cost for Years Ended December 31 Discount Rate 3.73 % 4.29 % 4.54 % 3.76 % 4.37 % 4.58 % Service Cost Interest Rate 3.88 % 4.53 % 4.81 % 3.90 % 4.64 % 4.87 % Interest Cost Interest Rate 3.35 % 3.63 % 3.75 % 3.39 % 3.69 % 3.76 % Expected Return on Plan Assets 7.80 % 7.80 % 8.00 % 7.80 % 7.80 % 8.00 % Rate of Compensation Increase 3.90 % 3.61 % 3.61 % 3.90 % 3.61 % 3.61 % Assumed Health Care Cost Trend Rates as of December 31 Health Care Costs Immediate Rate 7.28 % 7.93 % 7.55 % Ultimate Rate 4.75 % 4.75 % 4.75 % Year Ultimate Rate Reached 2026 2026 2025 Millions Effect of a 1% Increase in the Assumed Rate of Increase in Health Care Benefit Costs Total of Service Cost and Interest Cost $ 1 $ 13 $ 11 Postretirement Benefit Obligation $ 21 $ 240 $ 191 Effect of a 1% Decrease in the Assumed Rate of Increase in Health Care Benefit Costs Total of Service Cost and Interest Cost $ (1 ) $ (10 ) $ (9 ) Postretirement Benefit Obligation $ (20 ) $ (198 ) $ (160 ) Plan Assets The investments of pension and OPEB plans are held in a trust account by the Trustee and consist of an undivided interest in an investment account of the Master Trust. The investments in the pension and OPEB plans are measured at fair value within a hierarchy that prioritizes the inputs to fair value measurements into three levels. See Note 18. Fair Value Measurements for more information on fair value guidance. Use of the Master Trust permits the commingling of pension plan assets and OPEB plan assets for investment and administrative purposes. Although assets of the plans are commingled in the Master Trust, the Trustee maintains supporting records for the purpose of allocating the net gain or loss of the investment account to the respective participating plans. The net investment income of the investment assets is allocated by the Trustee to each participating plan based on the relationship of the interest of each plan to the total of the interests of the participating plans. As of December 31, 2018 , the pension plan interest and OPEB plan interest in such assets of the Master Trust were approximately 91% and 9% , respectively. The following tables present information about the investments measured at fair value on a recurring basis as of December 31, 2018 and 2017 , including the fair value measurements and the levels of inputs used in determining those fair values. Recurring Fair Value Measurements as of December 31, 2018 Quoted Market Prices for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Description Total (Level 1) (Level 2) (Level 3) Millions Cash Equivalents (A) $ 99 $ 88 $ 11 $ — Equity Securities Common Stock (B) 1,156 1,156 — — Commingled (C) 1,338 960 378 — Preferred Stock (B) 7 7 — — Other (D) 1 1 — — Debt Securities (E) U.S. Treasury 526 — 526 — Government—Other 302 — 302 — Corporate 948 — 948 — Subtotal Fair Value $ 4,377 $ 2,212 $ 2,165 $ — Measured at net asset value practical expedient Commingled—Equities (F) 1,208 Private Equity (G) 10 Total Fair Value (H) $ 5,595 Recurring Fair Value Measurements as of December 31, 2017 Quoted Market Prices for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Description Total (Level 1) (Level 2) (Level 3) Millions Cash Equivalents (A) $ 133 $ 117 $ 16 $ — Equity Securities Common Stock (B) 1,275 1,275 — — Commingled (C) 1,401 1,218 183 — Preferred Stock (B) 6 6 — — Debt Securities (E) U.S. Treasury 571 — 571 — Government—Other 272 — 272 — Corporate 963 — 963 — Subtotal Fair Value $ 4,621 $ 2,616 $ 2,005 $ — Measured at net asset value practical expedient Commingled—Equities (F) 1,675 Private Equity (G) 14 Total Fair Value (H) $ 6,310 (A) The Collective Investment Fund publishes a daily net asset value (NAV) which participants may use for daily redemptions without restrictions (Level 1). Certain temporary investments are valued using inputs such as time-to-maturity, coupon rate, quality rating and current yield (Level 2). (B) Common stocks and preferred stocks are measured using observable data in active markets and considered Level 1. (C) Commingled Funds that allow daily redemption at their daily published NAV without restrictions are classified as Level 1. Commingled Funds that publish daily NAV but with certain near-term redemption restrictions which prevent redemption at the published daily NAV are classified as Level 2. (D) Investment in a publicly traded limited partnership. (E) Debt securities include mainly investment grade corporate and municipal bonds, U.S. Treasury obligations and Federal Agency asset-backed securities with a wide range of maturities. These investments are valued using an evaluated pricing approach that varies by asset class and reflects observable market information such as the most recent exchange price or quoted bid for similar securities. Market-based standard inputs typically include benchmark yields, reported trades, broker/dealer quotes and issuer spreads or the most recent quotes for similar securities which are a Level 2 measure. (F) Certain commingled equity funds are not included in the fair value hierarchy as they are measured at fair value using the NAV per share (or its equivalent) practical expedient. These funds do not meet the definition of readily determinable fair value due to limitations in published NAV (last business day of the month) and include certain redemption restrictions ranging from one to fifteen days advance notice prior to redemption days and limitations on withdrawals over 25% of the total fund. The objectives of these funds are mainly tracking the S&P Index or achieving long-term growth through investment in foreign equity securities and the MSCI Emerging Markets Index. (G) Private equity investments primarily include various limited partnerships that invest in either operating companies through acquisitions or developing a portfolio of non-US distressed investments to maximize total return on capital. These investments are valued at NAV (or its equivalent) on an annual basis and have significant redemption restrictions preventing redemption until fund liquidation and limited ability to sell these investments. Fund liquidation is not expected to occur for several more years. These investments have been removed from the fair value hierarchy in accordance with the guidance on NAV practical expedient. (H) Excludes net receivables of $14 million and $13 million at December 31, 2018 and 2017 , respectively, which consist of interest, dividends and receivables and payables related to pending securities sales and purchases. The following table provides the percentage of fair value of total plan assets for each major category of plan assets held for the qualified pension and OPEB plans as of the measurement date, December 31: As of December 31, Investments 2018 2017 Equity Securities 66 % 69 % Debt Securities 32 29 Other Investments 2 2 Total Percentage 100 % 100 % PSEG utilizes forecasted returns, risk, and correlation of all asset classes in order to develop an efficient portfolio. PSEG’s latest asset/liability study indicates that a long-term target asset allocation of 70% equities and 30% fixed income is consistent with the funds’ financial objectives. Derivative financial instruments are used by the plans’ investment managers primarily to adjust the fixed income duration of the portfolio and hedge the currency risk component of foreign investments. The expected long-term rate of return on plan assets was 7.8% for 2018 and will be 7.8% for 2019 . This expected return was determined based on the study discussed above, including a premium for active management and considered the plans’ historical annualized rate of return since inception. Plan Contributions PSEG has no planned contributions to its pension plans in 2019 . PSEG plans to make discretionary contributions of $10 million into its OPEB plan during 2019 . Estimated Future Benefit Payments The following pension benefit and postretirement benefit payments are expected to be paid to plan participants. Year Pension Benefits Other Benefits Millions 2019 $ 345 $ 91 2020 341 95 2021 352 87 2022 364 88 2023 373 89 2024-2028 2,004 428 Total $ 3,779 $ 878 401(k) Plans PSEG sponsors two 401(k) plans, which are defined contribution retirement plans subject to the Employee Retirement Income Security Act (ERISA). Eligible represented employees of PSEG’s subsidiaries participate in the PSEG Employee Savings Plan (Savings Plan), while eligible non-represented employees of PSEG’s subsidiaries participate in the PSEG Thrift and Tax-Deferred Savings Plan (Thrift Plan). Eligible employees may contribute up to 50% of their compensation to these plans, not to exceed the Internal Revenue Service (IRS) maximums, including any catch-up contributions for those employees age 50 and above. PSEG matches 50% of such employee contributions up to 7% of pay for Savings Plan participants and up to 8% of pay for Thrift Plan participants. The amount paid for employer matching contributions to the plans for PSEG, PSE&G and Power are detailed as follows: Thrift Plan and Savings Plan Years Ended December 31, 2018 2017 2016 Millions PSE&G $ 26 $ 25 $ 24 Power 10 11 12 Other 5 5 5 Total Employer Matching Contributions $ 41 $ 41 $ 41 Servco Pension and OPEB At the direction of LIPA, effective January 1, 2014, Servco established benefit plans that provide substantially the same benefits to its employees as those previously provided by National Grid Electric Services LLC (NGES), the predecessor T&D system manager for LIPA. Since the vast majority of Servco’s employees had worked under NGES’ T&D operations services arrangement with LIPA, Servco’s plans provide certain of those employees with pension and OPEB vested credit for prior years’ services earned while working for NGES. The benefit plans cover all employees of Servco for current service. Under the OSA, all of these and any future employee benefit costs are to be funded by LIPA. See Note 5. Variable Interest Entity . These obligations, as well as the offsetting long-term receivable, are separately presented on the Consolidated Balance Sheet of PSEG. The following table provides a roll-forward of the changes in Servco’s benefit obligation and the fair value of its plan assets during the years ended December 31, 2018 and 2017 . It also provides the funded status of the plans and the amounts recognized and amounts not recognized on the Consolidated Balance Sheets at the end of both years. Pension Benefits Other Benefits 2018 2017 2018 2017 Millions Change in Benefit Obligation Benefit Obligation at Beginning of Year $ 320 $ 262 $ 542 $ 452 Service Cost 30 27 18 15 Interest Cost 12 11 20 19 Actuarial (Gain) Loss (38 ) 22 (73 ) 60 Gross Benefits Paid (3 ) (2 ) (6 ) (4 ) Plan Amendments — — — — Benefit Obligation at End of Year (A) $ 321 $ 320 $ 501 $ 542 Change in Plan Assets Fair Value of Assets at Beginning of Year $ 191 $ 134 $ — $ — Actual Return on Plan Assets (16 ) 24 — — Employer Contributions 40 35 6 4 Gross Benefits Paid (3 ) (2 ) (6 ) (4 ) Fair Value of Assets at End of Year $ 212 $ 191 $ — $ — Funded Status Funded Status (Plan Assets less Benefit Obligation) $ (109 ) $ (129 ) $ (501 ) $ (542 ) Additional Amounts Recognized in the Consolidated Balance Sheets Accrued Pension Costs of Servco $ (109 ) $ (129 ) N/A N/A OPEB Costs of Servco N/A N/A (501 ) (542 ) Amounts Recognized (B) $ (109 ) $ (129 ) $ (501 ) $ (542 ) (A) Represents projected benefit obligation for pension benefits and the accumulated postretirement benefit obligation for other benefits. The vested benefit obligation is the actuarial present value of the vested benefits to which the employee is currently entitled but based on the employee’s expected date of separation of retirement. (B) Amounts equal to the accrued pension and OPEB costs of Servco are offset in Long-Term Receivable of VIE on PSEG’s Consolidated Balance Sheets. Pension and OPEB costs of Servco are accounted for according to the OSA. Servco recognizes expenses for contributions to its pension plan trusts and for OPEB payments made to retirees. Operating Revenues are recognized for the reimbursement of these costs. The pension-related revenues and costs for 2018 , 2017 and 2016 were $40 million , $35 million and $28 million , respectively. Servco has contributed its entire planned contribution amount to its pension plan trusts during 2018 . The OPEB-related revenues earned and costs incurred were $6 million , $4 million and $2 million in 2018 , 2017 and 2016 , respectively. The following assumptions were used to determine the benefit obligations of Servco: Pension Benefits Other Benefits 2018 2017 2016 2018 2017 2016 Weighted-Average Assumptions Used to Determine Benefit Obligations as of December 31 Discount Rate 4.60 % 3.90 % 4.61 % 4.67 % 3.96 % 4.71 % Rate of Compensation Increase 3.25 % 3.25 % 3.25 % 3.25 % 3.25 % 3.25 % Assumed Health Care Cost Trend Rates as of December 31 Health Care Costs Immediate Rate 8.03 % 7.69 % 7.55 % Ultimate Rate 4.75 % 4.75 % 4.75 % Year Ultimate Rate Reached 2026 2026 2025 Millions Effect of a 1% Increase in the Assumed Rate of Increase in Health Care Benefit Costs Postretirement Benefit Obligation $ 108 $ 131 $ 97 Effect of a 1% Decrease in the Assumed Rate of Increase in Health Care Benefit Costs Postretirement Benefit Obligation $ (83 ) $ (99 ) $ (75 ) Plan Assets All the investments of Servco’s pension plans are held in a trust account by the Trustee and consist of an undivided interest in an investment account of the Master Trust. The investments in the pension are measured at fair value within a hierarchy that prioritizes the inputs to fair value measurements into three levels. See Note 18. Fair Value Measurements for more information on fair value guidance. The Actuary maintains supporting records for the purpose of allocating the net gain or loss of the investment account to the respective participating plans. The net investment income of the investment assets is allocated by the Actuary to each participating plan based on the relationship of the interest of each plan to the total of the interests of the participating plans. The following tables present information about Servco’s investments measured at fair value on a recurring basis as of December 31, 2018 and 2017 , including the fair value measurements and the levels of inputs used in determining those fair values. Recurring Fair Value Measurements as of December 31, 2018 Quoted Market Prices for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Description Total (Level 1) (Level 2) (Level 3) Millions Commingled Equities (A) $ 141 $ — $ 141 $ — Commingled Bonds (A) 71 — 71 — Total $ 212 $ — $ 212 $ — Recurring Fair Value Measurements as of December 31, 2017 Quoted Market Prices for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Description Total (Level 1) (Level 2) (Level 3) Millions Commingled Equities (A) $ 137 $ — $ 137 $ — Commingled Bonds (A) 54 — 54 — Total $ 191 $ — $ 191 $ — (A) Investments in commingled equity and bond funds have a readily determinable fair value as they publish a daily NAV available to investors which is the basis for current transactions and contain certain redemption restrictions requiring advance notice of one to two days for withdrawals (Level 2). The following table provides the percentage of fair value of total plan assets for each major category of plan assets held for the qualified pension and OPEB plans of Servco as of the measurement date, December 31: As of December 31, Investments 2018 2017 Equity Securities 67 % 72 % Debt Securities 33 28 Total Percentage 100 % 100 % Servco utilizes forecasted returns, risk, and correlation of all asset classes in order to develop an efficient portfolio. The results from Servco’s latest asset/liability study indicated that a long-term target asset allocation of 70% equities and 30% fixed income is consistent with the funds’ financial objectives. The expected long-term rate of return on plan assets was 7.6% for 2018 and will be 7.6% for 2019 . This expected return was determined based on the study discussed above, including a premium for active management. Plan Contributions Servco plans to contribute $28 million into its pension plan during 2019 . Estimated Future Benefit Payments The following pension benefit and postretirement benefit payments are expected to be paid to Servco’s plan participants: Year Pension Benefits Other Benefits Millions 2019 $ 4 $ 6 2020 6 8 2021 7 10 2022 9 12 2023 11 14 2024-2028 91 99 Total $ 128 $ 149 Servco 401(k) Plans Servco sponsors two 401(k) plans, which are defined contribution retirement plans subject to ERISA. Eligible non-represented employees of Servco participate in the Long Island Electric Utility Servco LLC Incentive Thrift Plan I (Thrift Plan I), and eligible represented employees of Servco participate in the Long Island Electric Utility Servco LLC Incentive Thrift Plan II (Thrift Plan II). Participants in the plans may contribute up to 50% of their eligible compensation to these plans, not to exceed the IRS maximums, including any catch-up contributions for those employees age 50 and above. Servco does not provide an employer match or core contribution for employees in Thrift Plan II. For employees in Thrift Plan I, Servco matches 50% of such employee contributions up to 8% of eligible compensation and provides core contributions (based on years of service and age) to employees who do not participate in Servco’s Retirement Income Plan. The amounts expensed by Servco for employer matching contributions for the years ended December 31, 2018 , 2017 and 2016 were $7 million , $6 million and $5 million , respectively, and pursuant to the OSA, Servco recognizes Operating Revenues for the reimbursement of these costs.

Commitments and Contingent Liab

Commitments and Contingent Liabilities	12 Months Ended
	Dec. 31, 2018
Other Commitments [Line Items]
Commitments and Contingent Liabilities	Commitments and Contingent Liabilities Guaranteed Obligations Power’s activities primarily involve the purchase and sale of energy and related products under transportation, physical, financial and forward contracts at fixed and variable prices. These transactions are with numerous counterparties and brokers that may require cash, cash-related instruments or guarantees as a form of collateral. Power has unconditionally guaranteed payments to counterparties by its subsidiaries in commodity-related transactions in order to • support current exposure, interest and other costs on sums due and payable in the ordinary course of business, and • obtain credit. Power is subject to • counterparty collateral calls related to commodity contracts, and • certain creditworthiness standards as guarantor under performance guarantees of its subsidiaries. Under these agreements, guarantees cover lines of credit between entities and are often reciprocal in nature. The exposure between counterparties can move in either direction. In order for Power to incur a liability for the face value of the outstanding guarantees, its subsidiaries would have to • fully utilize the credit granted to them by every counterparty to whom Power has provided a guarantee, and • the net position of the related contracts would have to be “out-of-the-money” (if the contracts are terminated, Power would owe money to the counterparties). Power believes the probability of this result is unlikely. For this reason, Power believes that the current exposure at any point in time is a more meaningful representation of the potential liability under these guarantees. Current exposure consists of the net of accounts receivable and accounts payable and the forward value on open positions, less any collateral posted. Changes in commodity prices can have a material impact on collateral requirements under such contracts, which are posted and received primarily in the form of cash and letters of credit. Power also routinely enters into futures and options transactions for electricity and natural gas as part of its operations. These futures contracts usually require a cash margin deposit with brokers, which can change based on market movement and in accordance with exchange rules. In addition to the guarantees discussed above, Power has also provided payment guarantees to third parties on behalf of its affiliated companies. These guarantees support various other non-commodity related contractual obligations. The following table shows the face value of Power’s outstanding guarantees, current exposure and margin positions as of December 31, 2018 and 2017 . As of December 31, 2018 As of December 31, 2017 Millions Face Value of Outstanding Guarantees $ 1,772 $ 1,701 Exposure under Current Guarantees $ 198 $ 153 Letters of Credit Margin Posted $ 115 $ 103 Letters of Credit Margin Received $ 26 $ 32 Cash Deposited and Received Counterparty Cash Margin Deposited $ — $ — Counterparty Cash Margin Received $ (10 ) $ (1 ) Net Broker Balance Deposited (Received) $ 403 $ 147 Additional Amounts Posted Other Letters of Credit $ 52 $ 61 As part of determining credit exposure, Power nets receivables and payables with the corresponding net fair values of energy contracts. See Note 17. Financial Risk Management Activities for further discussion. In accordance with PSEG’s accounting policy, where it is applicable, cash (received)/deposited is allocated against derivative asset and liability positions with the same counterparty on the face of the Consolidated Balance Sheet. The remaining balances of net cash (received)/deposited after allocation are generally included in Accounts Payable and Receivable, respectively. In addition to amounts for outstanding guarantees, current exposure and margin positions, PSEG and Power have posted letters of credit to support Power’s various other non-energy contractual and environmental obligations. See preceding table. Environmental Matters Passaic River Historic operations of PSEG companies and the operations of hundreds of other companies along the Passaic and Hackensack Rivers are alleged by Federal and State agencies to have discharged substantial contamination into the Passaic River/Newark Bay Complex in violation of various statutes as discussed as follows. Federal Comprehensive Environmental Response, Compensation and Liability Act of 1980 (CERCLA) The U.S. Environmental Protection Agency (EPA) has determined that a 17 -mile stretch of the lower Passaic River from Newark to Clifton, New Jersey is a “Superfund” site under CERCLA and a comprehensive study of the entire 17 miles of the lower Passaic River needed to be performed. PSE&G and certain of its predecessors conducted operations at properties in this area of the Passaic River. The properties included one operating electric generating station (Essex Site), which was transferred to Power, one former generating station and four former manufactured gas plant (MGP) sites. In early 2007, certain Potentially Responsible Parties (PRPs), including PSE&G and Power, formed a Cooperating Parties Group (CPG) and agreed to assume responsibility for conducting a Remedial Investigation and Feasibility Study (RI/FS) of the 17 miles of the lower Passaic River. The CPG has agreed to allocate, on an interim basis, the associated costs of the RI/FS among its members on the basis of a mutually agreed upon formula. For the purpose of this interim allocation, which has been revised as parties have exited the CPG, approximately 7.6 percent of the RI/FS costs are currently deemed attributable to PSE&G’s former MGP sites and approximately 1.9 percent is attributable to Power’s generating stations. These interim allocations are not binding on PSE&G or Power in terms of their respective shares of the costs that will be ultimately required to remediate the 17 miles of the lower Passaic River. PSEG has provided notice to insurers concerning this potential claim. The CPG’s draft FS set forth various alternatives for remediating the lower Passaic River with an estimated cost to remediate the lower 17 miles of the Passaic River ranging from approximately $518 million to $3.2 billion on an undiscounted basis. In March 2016, the EPA released its Record of Decision (ROD) for the EPA’s own Focused Feasibility Study (FFS) which requires the removal of 3.5 million cubic yards of sediment from the Passaic River’s lower 8.3 miles at an estimated cost of $2.3 billion on an undiscounted basis (ROD Remedy). The EPA estimated the total project length to be about 11 years, including a one year period of negotiation with the PRPs, three to four years to design the project and six years for implementation. Occidental Chemical Corporation (OCC), one of the PRPs, has commenced performance of the remedial design required by the ROD Remedy, reserving its right of cost contribution from all other PRPs. In September 2017, the EPA concluded that an Agency-commenced allocation process for the Passaic River’s lower 8.3 miles should include only certain PRPs. The allocation is intended to lead to a consent decree in which certain of the PRPs agree to perform and pay for the remedial action under EPA oversight. Due to delays from the partial federal government shutdown in late 2018 through early 2019, the timeline for completing the allocation process has been delayed. In October 2018, the EPA Region 2 issued a Directive to the CPG instructing the CPG to focus the ongoing RI/FS evaluation on various adaptive management scenarios for remediation of the upper 9 miles of the Passaic River, which approach has been agreed to in concept by the EPA and the CPG. The Directive does not contain estimates for anticipated costs. Adaptive management focuses on removing targeted “hot spots” of contaminated sediments rather than removing all of the Passaic River’s sediments as in a “bank to bank” approach. In a separate matter, two PRPs, Tierra Solutions, Inc. (Tierra) and Maxus Energy Corporation (Maxus), filed for Chapter 11 bankruptcy in Delaware Federal Bankruptcy Court. In June 2018, the trust representing the creditors in this proceeding filed a complaint asserting claims against the current and former parent entities of Tierra and Maxus, among other parties, for up to $14 billion . Any damages awarded may be used to fund, in part, the remediation costs of the lower 8.3 miles of the Passaic River. The creditor trust has reserved its right to file contribution claims against 28 PRPs, including PSEG. This matter is ongoing. In June 2018, OCC filed a complaint in Federal District Court in Newark against various defendants, including PSE&G, seeking cost recovery and contribution under CERCLA for the remediation of the lower 8.3 miles of the Passaic River. The complaint does not quantify damages sought. The Complaint alleges that “no single hazardous substance” is to blame for the contamination of the lower Passaic River and lists the eight Contaminants of Concern (COCs) identified by the EPA in the ROD. OCC alleges PSE&G is responsible for a portion of six of the eight COCs. PSE&G cannot predict the outcome of this matter. Based upon the estimated cost of the ROD Remedy and PSEG’s estimate of PSE&G’s and Power’s shares of that cost, as of December 31, 2018 , PSEG has accrued approximately $57 million . Of this amount, PSE&G has accrued $46 million as an Environmental Costs Liability and a corresponding Regulatory Asset based on its continued ability to recover such costs in its rates. Power has accrued $11 million as an Other Noncurrent Liability with the corresponding O&M Expense recorded in prior years when the liability was accrued. The EPA has broad authority to implement its selected remedy through the ROD and PSEG cannot at this time predict how the implementation of the ROD might impact PSE&G’s and Power’s ultimate liability. Until (i) the RI/FS, which covers the entire 17 miles of the lower Passaic River, is finalized either in whole or in part, (ii) an agreement by the PRPs to perform either the ROD Remedy as issued, or an amended ROD Remedy determined through negotiation or litigation, and an agreed upon remedy for the remaining 8.7 miles of the river, are reached, (iii) PSE&G’s and Power’s respective shares of the costs, both in the aggregate as well as individually, are determined, and (iv) PSE&G’s continued ability to recover the costs in its rates is determined, it is not possible to predict this matter’s ultimate impact on PSEG’s financial statements. It is possible that PSE&G and Power will record additional costs beyond what they have accrued, and that such costs could be material, but PSEG cannot at the current time estimate the amount or range of any additional costs. Natural Resource Damage Claims In 2003, the New Jersey Department of Environmental Protection (NJDEP) directed PSEG, PSE&G and 56 other PRPs to arrange for a natural resource damage assessment and interim compensatory restoration of natural resource injuries along the lower Passaic River and its tributaries pursuant to the New Jersey Spill Compensation and Control Act. The NJDEP alleged that hazardous substances had been discharged from the Essex Site and the Harrison Site. The NJDEP estimated the cost of interim natural resource injury restoration activities along the lower Passaic River at approximately $950 million . In 2007, agencies of the U.S. Department of Commerce and the U.S. Department of the Interior (the Passaic River federal trustees) sent letters to PSE&G and other PRPs inviting participation in an assessment of injuries to natural resources that the agencies intended to perform. In 2008, PSEG and a number of other PRPs agreed to share certain immaterial costs the trustees have incurred and will incur going forward, and to work with the trustees to explore whether some or all of the trustees’ claims can be resolved in a cooperative fashion. That effort is continuing. PSE&G and Power are unable to estimate their respective portions of the possible loss or range of loss related to this matter. Newark Bay Study Area The EPA has established the Newark Bay Study Area, which it defines as Newark Bay and portions of the Hackensack River, the Arthur Kill and the Kill Van Kull. In August 2006, the EPA sent PSEG and 11 other entities notices that it considered each of the entities to be a PRP with respect to contamination in the Study Area. The notice letter requested that the PRPs fund an EPA-approved study in the Newark Bay Study Area. The notice stated the EPA’s belief that hazardous substances were released from sites owned by PSEG companies and located on the Hackensack River, including two electric generating stations (Hudson and Kearny sites) and one former MGP site. PSEG has participated in and partially funded the second phase of this study. Notices to fund the next phase of the study have been received but PSEG has not consented to fund the third phase. PSE&G and Power are unable to estimate their respective portions of the possible loss or range of loss related to this matter. In December 2018, Power completed the sale of the site of the Hudson electric generating station. Power transferred all land rights and structures on the site to a third party purchaser, along with the assumption of the environmental liabilities for the site. MGP Remediation Program PSE&G is working with the NJDEP to assess, investigate and remediate environmental conditions at its former MGP sites. To date, 38 sites requiring some level of remedial action have been identified. Based on its current studies, PSE&G has determined that the estimated cost to remediate all MGP sites to completion could range between $321 million and $366 million on an undiscounted basis through 2021, including its $46 million share for the Passaic River as discussed above. Since no amount within the range is considered to be most likely, PSE&G has recorded a liability of $321 million as of December 31, 2018 . Of this amount, $56 million was recorded in Other Current Liabilities and $265 million was reflected as Environmental Costs in Noncurrent Liabilities. PSE&G has recorded a $321 million Regulatory Asset with respect to these costs. PSE&G periodically updates its studies taking into account any new regulations or new information which could impact future remediation costs and adjusts its recorded liability accordingly. NJDEP, PSEG and EPA representatives have had discussions regarding to what extent sampling in the Passaic River is required to delineate coal tar from MGP sites that abut the Passaic River Superfund site. PSEG cannot determine at this time whether this will have an impact on the Passaic River Superfund remedy. Clean Water Act (CWA) Permit Renewals Pursuant to the Federal Water Pollution Control Act, National Pollutant Discharge Elimination System permits expire within five years of their effective date. In order to renew these permits, but allow a plant to continue to operate, an owner or operator must file a permit application no later than six months prior to expiration of the permit. States with delegated federal authority for this program manage these permits. The NJDEP manages the permits under the New Jersey Pollutant Discharge Elimination System (NJPDES) program. Connecticut and New York also have permits to manage their respective pollutant discharge elimination system programs. In May 2014, the EPA issued a final cooling water intake rule that establishes requirements for the regulation of cooling water intakes at existing power plants and industrial facilities with a design flow of more than two million gallons of water per day. The EPA has structured the rule so that each state Permitting Director will continue to consider renewal permits for existing power facilities on a case by case basis, based on studies related to impingement mortality and entrainment by the facilities seeking renewal permits. Several environmental organizations and certain energy industry groups have filed suit under the CWA and the Endangered Species Act. The cases were consolidated at the Second Circuit, and in July 2018 the Second Circuit upheld the EPA’s final cooling water intake rule. The Court’s decision allows Permitting Directors to continue to issue permits in accordance with the flexible, site-specific provisions of the final rule. In June 2016, the NJDEP issued a final NJPDES permit for Salem. The final permit does not mandate specific service water system modifications, but consistent with Section 316 (b) of the CWA, it requires additional studies and the selection of technology to address impingement for the service water system. In July 2016, the Delaware Riverkeeper Network (Riverkeeper) filed a request challenging the NJDEP’s issuance of the final NJPDES renewal permit for Salem. NJDEP has granted the hearing request, but it has not yet been scheduled. The Riverkeeper’s filing does not change the effective date of the permit. If the Riverkeeper’s challenge were successful, Power may be required to incur additional costs to comply with the CWA. Potential cooling water system modification costs could be material and could adversely impact the economic competitiveness of this facility. State permitting decisions at Bridgeport and possibly New Haven could also have a material impact on Power’s ability to renew permits at its existing larger once-through cooled plants without making significant upgrades to existing intakes and cooling systems. Power is unable to predict the outcome of these permitting decisions and the effect, if any, that they may have on Power’s future capital requirements, financial condition or results of operations. Power is actively engaged with the Connecticut Department of Energy and Environmental Protection (CTDEEP) regarding renewal of the current permit for the cooling water intake structure at Bridgeport Harbor Station Unit 3 (BH3). To address compliance with the EPA’s CWA Section 316(b) final rule, Power has proposed to continue to operate BH3 without making the capital expenditures for modification to the existing intake structure and retire BH3 in 2021, which is four years earlier than the previously estimated useful life ending in 2025. Power is currently awaiting action by the CTDEEP to issue a draft and then a final permit. Power has entered into a Community Environmental Benefit Agreement (CEBA) with the City of Bridgeport, Connecticut and local community organizations. That CEBA provides that Power would retire BH3 early if all of its conditions precedent occur, which include receipt of all final permits to build and operate a proposed new combined cycle generating facility on the same site that BH3 currently operates. Absent those conditions being met, and the permit for the cooling water intake structure referred to above not being issued, Power may seek to operate BH3 through the previously estimated useful life. In February 2016, the proposed new generating facility at Bridgeport Harbor was awarded a capacity obligation. The Connecticut Siting Council issued an order to approve siting Bridgeport Harbor Station Unit 5. Operations are expected to begin in mid-2019. Power’s obligations under the CEBA are being monitored regularly and carried out as needed. Jersey City, New Jersey Subsurface Feeder Cable Matter In October 2016, a discharge of dielectric fluid from subsurface feeder cables located in the Hudson River near Jersey City, New Jersey, was identified and reported to the NJDEP. The feeder cables are located within a subsurface easement granted to PSE&G by the property owners, Newport Associates Development Company (NADC) and Newport Associates Phase I Developer Limited Partnership. The feeder cables are subject to agreements between PSE&G and Consolidated Edison Company of New York, Inc. (Con Edison) and are jointly owned by PSE&G and Con Edison, with PSE&G owning the portion of the cables located in New Jersey and Con Edison owning the portion of the cables located in New York. The NJDEP declared an emergency and an emergency response action was undertaken to investigate, contain, remediate and stop the fluid discharge; to assess, repair and restore the cables to good working order, if feasible; and to restore the property. The regulatory agencies overseeing the emergency response, including the U.S. Coast Guard, the NJDEP and the Army Corps of Engineers, issued multiple notices, orders and directives to the various parties related to this matter and the parties may also be subject to the assessment of civil penalties related to the discharge and response. The U.S. Coast Guard transitioned control of the federal response to the EPA in May 2018. In August 2018, the EPA ended the federal response to the matter. The response has now transitioned to the NJDEP site remediation program. The impacted cable was repaired in late September 2017; however, small amounts of residual dielectric fluid believed to be contained within the marina sediment continue to appear on the surface and response actions related to the fluid discharge are ongoing, although at a significantly reduced scale. PSE&G remains concerned about future leaks and potential environmental impacts as a result of reintroduction of fluid back into these lines and has determined that retirement of the affected facilities is appropriate. PSE&G has been unable to reach an agreement with Con Edison and, as a result, in May 2018, PSE&G filed an action at FERC to resolve the matter. FERC dismissed PSE&G’s Complaint against Con Edison in September 2018 and PSE&G has challenged FERC’s decision. Also ongoing is the lawsuit in federal court to determine ultimate responsibility for the costs to address the leak among PSE&G, Con Edison and NADC. In addition, Con Edison filed counter claims against PSE&G and NADC, including seeking injunctive relief and damages. Based on the information currently available and depending on the outcome of the federal court action, PSE&G’s portion of the costs to address the leak may be material; however, PSE&G anticipates that it will recover these costs through regulatory proceedings. Steam Electric Effluent Guidelines In September 2015, the EPA issued a new Effluent Limitation Guidelines Rule (ELG Rule) for steam electric generating units. The rule establishes new best available technology economically achievable (BAT) standards for fly ash transport water, bottom ash transport water, flue gas desulfurization and flue gas mercury control wastewater. Power’s Bridgeport Harbor station and the jointly-owned Keystone and Conemaugh stations, have bottom ash transport water discharges that are regulated under the ELG Rule. Keystone and Conemaugh also have flue gas desulfurization wastewaters regulated by the ELG Rule. Through various orders, the EPA has stayed the compliance dates in the ELG Rule and has announced plans to further revise the requirements and compliance dates of the ELG Rule. Power is unable to determine how this will ultimately impact its compliance requirements or its financial condition and results of operations. Basic Generation Service (BGS) and Basic Gas Supply Service (BGSS) PSE&G obtains its electric supply requirements through the annual New Jersey BGS auctions for two categories of customers who choose not to purchase electric supply from third-party suppliers. The first category, which represents about 80% of PSE&G’s load requirement, is residential and smaller commercial and industrial customers (BGS-Residential Small Commercial Pricing (RSCP)). The second category is larger customers that exceed a BPU-established load (kW) threshold (BGS-Commercial and Industrial Energy Pricing (CIEP)). Pursuant to applicable BPU rules, PSE&G enters into the Supplier Master Agreement with the winners of these BGS auctions following the BPU’s approval of the auction results. PSE&G has entered into contracts with winning BGS suppliers, including Power, to purchase BGS for PSE&G’s load requirements. The winners of the auction (including Power) are responsible for fulfilling all the requirements of a PJM Load-Serving Entity including the provision of capacity, energy, ancillary services, transmission and any other services required by PJM. BGS suppliers assume all volume risk and customer migration risk and must satisfy New Jersey’s renewable portfolio standards. The BGS-CIEP auction is for a one-year supply period from June 1 to May 31 with the BGS-CIEP auction price measured in dollars per MW-day for capacity. The final price for the BGS-CIEP auction year commencing June 1, 2019 is $281.78 per MW-day, replacing the BGS-CIEP auction year price ending May 31, 2019 of $287.76 per MW-day. Energy for BGS-CIEP is priced at hourly PJM locational marginal prices for the contract period. PSE&G contracts for its anticipated BGS-RSCP load on a three-year rolling basis, whereby each year one-third of the load is procured for a three-year period. The contract prices in dollars per MWh for the BGS-RSCP supply, as well as the approximate load, are as follows: Auction Year 2016 2017 2018 2019 36-Month Terms Ending May 2019 May 2020 May 2021 May 2022 (A) Load (MW) 2,800 2,800 2,900 2,800 $ per MWh $96.38 $90.78 $91.77 $98.04 (A) Prices set in the 2019 BGS auction will become effective on June 1, 2019 when the 2016 BGS auction agreements expire. Power seeks to mitigate volatility in its results by contracting in advance for the sale of most of its anticipated electric output as well as its anticipated fuel needs. As part of its objective, Power has entered into contracts to directly supply PSE&G and other New Jersey electric distribution companies with a portion of their respective BGS requirements through the New Jersey BGS auction process, described above. PSE&G has a full-requirements contract with Power to meet the gas supply requirements of PSE&G’s gas customers. Power has entered into hedges for a portion of these anticipated BGSS obligations, as permitted by the BPU. The BPU permits PSE&G to recover the cost of gas hedging up to 115 billion cubic feet or 80% of its residential gas supply annual requirements through the BGSS tariff. Current plans call for Power to hedge on behalf of PSE&G approximately 70 billion cubic feet or 50% of its residential gas supply annual requirements. For additional information, see Note 25. Related-Party Transactions . Minimum Fuel Purchase Requirements Power’s nuclear fuel strategy is to maintain certain levels of uranium and to make periodic purchases to support such levels. As such, the commitments referred to in the following table may include estimated quantities to be purchased that deviate from contractual nominal quantities. Power’s nuclear fuel commitments cover approximately 100% of its estimated uranium, enrichment and fabrication requirements through 2020 and a significant portion through 2021 at Salem, Hope Creek and Peach Bottom. Power has various multi-year contracts for natural gas and firm transportation and storage capacity for natural gas that are primarily used to meet its obligations to PSE&G. When there is excess delivery capacity available beyond the needs of PSE&G’s customers, Power can use the gas to supply its fossil generating stations in New Jersey. Power also has various long-term fuel purchase commitments for coal through 2023 to support its fossil generation stations. As of December 31, 2018 , the total minimum purchase requirements included in these commitments were as follows: Fuel Type Power's Share of Commitments through 2023 Millions Nuclear Fuel Uranium $ 222 Enrichment $ 358 Fabrication $ 167 Natural Gas $ 1,102 Coal $ 429 Pending FERC Matters In June 2015, Transource LLC, a merchant transmission developer, filed a complaint against PJM claiming that PJM wrongfully refused to provide data and a transparent process for evaluating transmission network upgrade requests that the transmission developer had submitted to PJM. Although not named as a respondent, the complaint identifies PSE&G as one of the companies claimed to have been involved. In January 2018, a FERC administrative law judge (ALJ) issued an order generally finding that PJM and transmission owners, including PSE&G, did not engage in wrongful conduct. In addition, the developer’s assertion of an entitlement to monetary damages was expressly denied. However, in a determination disputed by PSE&G, the order found that the PJM process lacked transparency. The judge’s order has been briefed by all parties for additional determinations by FERC. We are unable to predict the outcome of these proceedings. Subsequent to the ALJ decision, PSE&G received requests for information from FERC’s Office of Enforcement concerning a transmission project. PSE&G is complying with these requests and cannot predict the outcome of this matter. Litigation Sewaren 7 Construction In June 2018, a complaint was filed in federal court in Newark, New Jersey against PSEG Fossil LLC, a wholly owned subsidiary of Power, regarding an ongoing dispute with Durr Mechanical Construction, Inc. (Durr), a contractor on the Sewaren 7 project. Among other things, Durr seeks damages of $93 million and alleges that Power withheld money owed to Durr and that Power’s intentional conduct led to the inability of Durr to obtain prospective contracts. Power intends to vigorously defend against these allegations. In December 2018, Durr filed for Chapter 11 bankruptcy in the federal court in the Southern District of New York (SDNY). The SDNY bankruptcy court has allowed the New Jersey litigation to proceed. Power has accrued an amount related to outstanding invoices which does not reflect an assessment of claims and potential counterclaims in this matter. Due to its preliminary nature, Power cannot predict the outcome of this matter. Newark Customer Incident On the morning of July 5, 2018, PSE&G discontinued electricity to the home of a customer residing in Newark because of outstanding arrears on that customer’s account. Subsequent to the discontinuation of electricity, that customer died on the afternoon of July 5th. The family of the customer, who was on hospice care, raised allegations in the media regarding PSE&G’s conduct surrounding the discontinuation and restoration of electricity to the home of the customer, claiming that the discontinuation of electric service prevented the customer from using life sustaining medical equipment. The BPU initiated an investigation into the matter and that investigation is ongoing. In addition, PSE&G received a grand jury subpoena from the Essex County Prosecutor’s Office (ECPO) for records and correspondence between PSE&G and the customer. PSE&G is fully cooperating with the BPU and the ECPO in both proceedings. PSEG cannot predict the outcome of the pending proceedings regarding this incident at this time. The PSEG Board of Directors (PSEG Board) retained outside counsel to conduct an independent investigation of the facts surrounding this incident with the full support and cooperation of management. The independent investigation concluded that the disconnection itself was not improper; however, it did identify issues related to PSE&G’s response once it was notified of the disconnection. The PSEG Board reviewed and considered the findings and conclusions of the investigation and PSE&G’s proposed corrective actions. PSE&G’s progress on implementation of the corrective actions will continue to be overseen by the PSEG Board. Caithness Energy, L.L.C. (Caithness) In August 2018, Caithness, a Long Island power plant developer, filed a complaint in federal district court in the Eastern District of New York against PSEG and PSEG LI alleging violations of state and federal antitrust laws and a claim of intentional interference of prospective business relations. Caithness alleges that PSEG and PSEG LI interfered with LIPA’s consideration of the Caithness proposal for a 750 MW combined cycle generation project that was identified as a finalist for a Request For Proposal issued by LIPA. In addition, Caithness claims that PSEG and PSEG LI induced LIPA to agree to eliminate the proposed project as a potential competitor to other PSEG affiliates with power supply operations. The complaint alleges hundreds of millions of dollars of harm and seeks treble and punitive damages. PSEG intends to vigorously defend against these allegations. Based upon the preliminary nature of this matter, a loss is not considered probable nor is the amount of loss, if any, estimable as of December 31, 2018 . Transource LLC (Transource) In January 2019, Transource filed a complaint against PJM, PSE&G and three other transmission owners in Pennsylvania state court. Transource has sued the transmission owner defendants for fraud and
PSE&G [Member]
Other Commitments [Line Items]
Commitments and Contingent Liabilities	Commitments and Contingent Liabilities Guaranteed Obligations Power’s activities primarily involve the purchase and sale of energy and related products under transportation, physical, financial and forward contracts at fixed and variable prices. These transactions are with numerous counterparties and brokers that may require cash, cash-related instruments or guarantees as a form of collateral. Power has unconditionally guaranteed payments to counterparties by its subsidiaries in commodity-related transactions in order to • support current exposure, interest and other costs on sums due and payable in the ordinary course of business, and • obtain credit. Power is subject to • counterparty collateral calls related to commodity contracts, and • certain creditworthiness standards as guarantor under performance guarantees of its subsidiaries. Under these agreements, guarantees cover lines of credit between entities and are often reciprocal in nature. The exposure between counterparties can move in either direction. In order for Power to incur a liability for the face value of the outstanding guarantees, its subsidiaries would have to • fully utilize the credit granted to them by every counterparty to whom Power has provided a guarantee, and • the net position of the related contracts would have to be “out-of-the-money” (if the contracts are terminated, Power would owe money to the counterparties). Power believes the probability of this result is unlikely. For this reason, Power believes that the current exposure at any point in time is a more meaningful representation of the potential liability under these guarantees. Current exposure consists of the net of accounts receivable and accounts payable and the forward value on open positions, less any collateral posted. Changes in commodity prices can have a material impact on collateral requirements under such contracts, which are posted and received primarily in the form of cash and letters of credit. Power also routinely enters into futures and options transactions for electricity and natural gas as part of its operations. These futures contracts usually require a cash margin deposit with brokers, which can change based on market movement and in accordance with exchange rules. In addition to the guarantees discussed above, Power has also provided payment guarantees to third parties on behalf of its affiliated companies. These guarantees support various other non-commodity related contractual obligations. The following table shows the face value of Power’s outstanding guarantees, current exposure and margin positions as of December 31, 2018 and 2017 . As of December 31, 2018 As of December 31, 2017 Millions Face Value of Outstanding Guarantees $ 1,772 $ 1,701 Exposure under Current Guarantees $ 198 $ 153 Letters of Credit Margin Posted $ 115 $ 103 Letters of Credit Margin Received $ 26 $ 32 Cash Deposited and Received Counterparty Cash Margin Deposited $ — $ — Counterparty Cash Margin Received $ (10 ) $ (1 ) Net Broker Balance Deposited (Received) $ 403 $ 147 Additional Amounts Posted Other Letters of Credit $ 52 $ 61 As part of determining credit exposure, Power nets receivables and payables with the corresponding net fair values of energy contracts. See Note 17. Financial Risk Management Activities for further discussion. In accordance with PSEG’s accounting policy, where it is applicable, cash (received)/deposited is allocated against derivative asset and liability positions with the same counterparty on the face of the Consolidated Balance Sheet. The remaining balances of net cash (received)/deposited after allocation are generally included in Accounts Payable and Receivable, respectively. In addition to amounts for outstanding guarantees, current exposure and margin positions, PSEG and Power have posted letters of credit to support Power’s various other non-energy contractual and environmental obligations. See preceding table. Environmental Matters Passaic River Historic operations of PSEG companies and the operations of hundreds of other companies along the Passaic and Hackensack Rivers are alleged by Federal and State agencies to have discharged substantial contamination into the Passaic River/Newark Bay Complex in violation of various statutes as discussed as follows. Federal Comprehensive Environmental Response, Compensation and Liability Act of 1980 (CERCLA) The U.S. Environmental Protection Agency (EPA) has determined that a 17 -mile stretch of the lower Passaic River from Newark to Clifton, New Jersey is a “Superfund” site under CERCLA and a comprehensive study of the entire 17 miles of the lower Passaic River needed to be performed. PSE&G and certain of its predecessors conducted operations at properties in this area of the Passaic River. The properties included one operating electric generating station (Essex Site), which was transferred to Power, one former generating station and four former manufactured gas plant (MGP) sites. In early 2007, certain Potentially Responsible Parties (PRPs), including PSE&G and Power, formed a Cooperating Parties Group (CPG) and agreed to assume responsibility for conducting a Remedial Investigation and Feasibility Study (RI/FS) of the 17 miles of the lower Passaic River. The CPG has agreed to allocate, on an interim basis, the associated costs of the RI/FS among its members on the basis of a mutually agreed upon formula. For the purpose of this interim allocation, which has been revised as parties have exited the CPG, approximately 7.6 percent of the RI/FS costs are currently deemed attributable to PSE&G’s former MGP sites and approximately 1.9 percent is attributable to Power’s generating stations. These interim allocations are not binding on PSE&G or Power in terms of their respective shares of the costs that will be ultimately required to remediate the 17 miles of the lower Passaic River. PSEG has provided notice to insurers concerning this potential claim. The CPG’s draft FS set forth various alternatives for remediating the lower Passaic River with an estimated cost to remediate the lower 17 miles of the Passaic River ranging from approximately $518 million to $3.2 billion on an undiscounted basis. In March 2016, the EPA released its Record of Decision (ROD) for the EPA’s own Focused Feasibility Study (FFS) which requires the removal of 3.5 million cubic yards of sediment from the Passaic River’s lower 8.3 miles at an estimated cost of $2.3 billion on an undiscounted basis (ROD Remedy). The EPA estimated the total project length to be about 11 years, including a one year period of negotiation with the PRPs, three to four years to design the project and six years for implementation. Occidental Chemical Corporation (OCC), one of the PRPs, has commenced performance of the remedial design required by the ROD Remedy, reserving its right of cost contribution from all other PRPs. In September 2017, the EPA concluded that an Agency-commenced allocation process for the Passaic River’s lower 8.3 miles should include only certain PRPs. The allocation is intended to lead to a consent decree in which certain of the PRPs agree to perform and pay for the remedial action under EPA oversight. Due to delays from the partial federal government shutdown in late 2018 through early 2019, the timeline for completing the allocation process has been delayed. In October 2018, the EPA Region 2 issued a Directive to the CPG instructing the CPG to focus the ongoing RI/FS evaluation on various adaptive management scenarios for remediation of the upper 9 miles of the Passaic River, which approach has been agreed to in concept by the EPA and the CPG. The Directive does not contain estimates for anticipated costs. Adaptive management focuses on removing targeted “hot spots” of contaminated sediments rather than removing all of the Passaic River’s sediments as in a “bank to bank” approach. In a separate matter, two PRPs, Tierra Solutions, Inc. (Tierra) and Maxus Energy Corporation (Maxus), filed for Chapter 11 bankruptcy in Delaware Federal Bankruptcy Court. In June 2018, the trust representing the creditors in this proceeding filed a complaint asserting claims against the current and former parent entities of Tierra and Maxus, among other parties, for up to $14 billion . Any damages awarded may be used to fund, in part, the remediation costs of the lower 8.3 miles of the Passaic River. The creditor trust has reserved its right to file contribution claims against 28 PRPs, including PSEG. This matter is ongoing. In June 2018, OCC filed a complaint in Federal District Court in Newark against various defendants, including PSE&G, seeking cost recovery and contribution under CERCLA for the remediation of the lower 8.3 miles of the Passaic River. The complaint does not quantify damages sought. The Complaint alleges that “no single hazardous substance” is to blame for the contamination of the lower Passaic River and lists the eight Contaminants of Concern (COCs) identified by the EPA in the ROD. OCC alleges PSE&G is responsible for a portion of six of the eight COCs. PSE&G cannot predict the outcome of this matter. Based upon the estimated cost of the ROD Remedy and PSEG’s estimate of PSE&G’s and Power’s shares of that cost, as of December 31, 2018 , PSEG has accrued approximately $57 million . Of this amount, PSE&G has accrued $46 million as an Environmental Costs Liability and a corresponding Regulatory Asset based on its continued ability to recover such costs in its rates. Power has accrued $11 million as an Other Noncurrent Liability with the corresponding O&M Expense recorded in prior years when the liability was accrued. The EPA has broad authority to implement its selected remedy through the ROD and PSEG cannot at this time predict how the implementation of the ROD might impact PSE&G’s and Power’s ultimate liability. Until (i) the RI/FS, which covers the entire 17 miles of the lower Passaic River, is finalized either in whole or in part, (ii) an agreement by the PRPs to perform either the ROD Remedy as issued, or an amended ROD Remedy determined through negotiation or litigation, and an agreed upon remedy for the remaining 8.7 miles of the river, are reached, (iii) PSE&G’s and Power’s respective shares of the costs, both in the aggregate as well as individually, are determined, and (iv) PSE&G’s continued ability to recover the costs in its rates is determined, it is not possible to predict this matter’s ultimate impact on PSEG’s financial statements. It is possible that PSE&G and Power will record additional costs beyond what they have accrued, and that such costs could be material, but PSEG cannot at the current time estimate the amount or range of any additional costs. Natural Resource Damage Claims In 2003, the New Jersey Department of Environmental Protection (NJDEP) directed PSEG, PSE&G and 56 other PRPs to arrange for a natural resource damage assessment and interim compensatory restoration of natural resource injuries along the lower Passaic River and its tributaries pursuant to the New Jersey Spill Compensation and Control Act. The NJDEP alleged that hazardous substances had been discharged from the Essex Site and the Harrison Site. The NJDEP estimated the cost of interim natural resource injury restoration activities along the lower Passaic River at approximately $950 million . In 2007, agencies of the U.S. Department of Commerce and the U.S. Department of the Interior (the Passaic River federal trustees) sent letters to PSE&G and other PRPs inviting participation in an assessment of injuries to natural resources that the agencies intended to perform. In 2008, PSEG and a number of other PRPs agreed to share certain immaterial costs the trustees have incurred and will incur going forward, and to work with the trustees to explore whether some or all of the trustees’ claims can be resolved in a cooperative fashion. That effort is continuing. PSE&G and Power are unable to estimate their respective portions of the possible loss or range of loss related to this matter. Newark Bay Study Area The EPA has established the Newark Bay Study Area, which it defines as Newark Bay and portions of the Hackensack River, the Arthur Kill and the Kill Van Kull. In August 2006, the EPA sent PSEG and 11 other entities notices that it considered each of the entities to be a PRP with respect to contamination in the Study Area. The notice letter requested that the PRPs fund an EPA-approved study in the Newark Bay Study Area. The notice stated the EPA’s belief that hazardous substances were released from sites owned by PSEG companies and located on the Hackensack River, including two electric generating stations (Hudson and Kearny sites) and one former MGP site. PSEG has participated in and partially funded the second phase of this study. Notices to fund the next phase of the study have been received but PSEG has not consented to fund the third phase. PSE&G and Power are unable to estimate their respective portions of the possible loss or range of loss related to this matter. In December 2018, Power completed the sale of the site of the Hudson electric generating station. Power transferred all land rights and structures on the site to a third party purchaser, along with the assumption of the environmental liabilities for the site. MGP Remediation Program PSE&G is working with the NJDEP to assess, investigate and remediate environmental conditions at its former MGP sites. To date, 38 sites requiring some level of remedial action have been identified. Based on its current studies, PSE&G has determined that the estimated cost to remediate all MGP sites to completion could range between $321 million and $366 million on an undiscounted basis through 2021, including its $46 million share for the Passaic River as discussed above. Since no amount within the range is considered to be most likely, PSE&G has recorded a liability of $321 million as of December 31, 2018 . Of this amount, $56 million was recorded in Other Current Liabilities and $265 million was reflected as Environmental Costs in Noncurrent Liabilities. PSE&G has recorded a $321 million Regulatory Asset with respect to these costs. PSE&G periodically updates its studies taking into account any new regulations or new information which could impact future remediation costs and adjusts its recorded liability accordingly. NJDEP, PSEG and EPA representatives have had discussions regarding to what extent sampling in the Passaic River is required to delineate coal tar from MGP sites that abut the Passaic River Superfund site. PSEG cannot determine at this time whether this will have an impact on the Passaic River Superfund remedy. Clean Water Act (CWA) Permit Renewals Pursuant to the Federal Water Pollution Control Act, National Pollutant Discharge Elimination System permits expire within five years of their effective date. In order to renew these permits, but allow a plant to continue to operate, an owner or operator must file a permit application no later than six months prior to expiration of the permit. States with delegated federal authority for this program manage these permits. The NJDEP manages the permits under the New Jersey Pollutant Discharge Elimination System (NJPDES) program. Connecticut and New York also have permits to manage their respective pollutant discharge elimination system programs. In May 2014, the EPA issued a final cooling water intake rule that establishes requirements for the regulation of cooling water intakes at existing power plants and industrial facilities with a design flow of more than two million gallons of water per day. The EPA has structured the rule so that each state Permitting Director will continue to consider renewal permits for existing power facilities on a case by case basis, based on studies related to impingement mortality and entrainment by the facilities seeking renewal permits. Several environmental organizations and certain energy industry groups have filed suit under the CWA and the Endangered Species Act. The cases were consolidated at the Second Circuit, and in July 2018 the Second Circuit upheld the EPA’s final cooling water intake rule. The Court’s decision allows Permitting Directors to continue to issue permits in accordance with the flexible, site-specific provisions of the final rule. In June 2016, the NJDEP issued a final NJPDES permit for Salem. The final permit does not mandate specific service water system modifications, but consistent with Section 316 (b) of the CWA, it requires additional studies and the selection of technology to address impingement for the service water system. In July 2016, the Delaware Riverkeeper Network (Riverkeeper) filed a request challenging the NJDEP’s issuance of the final NJPDES renewal permit for Salem. NJDEP has granted the hearing request, but it has not yet been scheduled. The Riverkeeper’s filing does not change the effective date of the permit. If the Riverkeeper’s challenge were successful, Power may be required to incur additional costs to comply with the CWA. Potential cooling water system modification costs could be material and could adversely impact the economic competitiveness of this facility. State permitting decisions at Bridgeport and possibly New Haven could also have a material impact on Power’s ability to renew permits at its existing larger once-through cooled plants without making significant upgrades to existing intakes and cooling systems. Power is unable to predict the outcome of these permitting decisions and the effect, if any, that they may have on Power’s future capital requirements, financial condition or results of operations. Power is actively engaged with the Connecticut Department of Energy and Environmental Protection (CTDEEP) regarding renewal of the current permit for the cooling water intake structure at Bridgeport Harbor Station Unit 3 (BH3). To address compliance with the EPA’s CWA Section 316(b) final rule, Power has proposed to continue to operate BH3 without making the capital expenditures for modification to the existing intake structure and retire BH3 in 2021, which is four years earlier than the previously estimated useful life ending in 2025. Power is currently awaiting action by the CTDEEP to issue a draft and then a final permit. Power has entered into a Community Environmental Benefit Agreement (CEBA) with the City of Bridgeport, Connecticut and local community organizations. That CEBA provides that Power would retire BH3 early if all of its conditions precedent occur, which include receipt of all final permits to build and operate a proposed new combined cycle generating facility on the same site that BH3 currently operates. Absent those conditions being met, and the permit for the cooling water intake structure referred to above not being issued, Power may seek to operate BH3 through the previously estimated useful life. In February 2016, the proposed new generating facility at Bridgeport Harbor was awarded a capacity obligation. The Connecticut Siting Council issued an order to approve siting Bridgeport Harbor Station Unit 5. Operations are expected to begin in mid-2019. Power’s obligations under the CEBA are being monitored regularly and carried out as needed. Jersey City, New Jersey Subsurface Feeder Cable Matter In October 2016, a discharge of dielectric fluid from subsurface feeder cables located in the Hudson River near Jersey City, New Jersey, was identified and reported to the NJDEP. The feeder cables are located within a subsurface easement granted to PSE&G by the property owners, Newport Associates Development Company (NADC) and Newport Associates Phase I Developer Limited Partnership. The feeder cables are subject to agreements between PSE&G and Consolidated Edison Company of New York, Inc. (Con Edison) and are jointly owned by PSE&G and Con Edison, with PSE&G owning the portion of the cables located in New Jersey and Con Edison owning the portion of the cables located in New York. The NJDEP declared an emergency and an emergency response action was undertaken to investigate, contain, remediate and stop the fluid discharge; to assess, repair and restore the cables to good working order, if feasible; and to restore the property. The regulatory agencies overseeing the emergency response, including the U.S. Coast Guard, the NJDEP and the Army Corps of Engineers, issued multiple notices, orders and directives to the various parties related to this matter and the parties may also be subject to the assessment of civil penalties related to the discharge and response. The U.S. Coast Guard transitioned control of the federal response to the EPA in May 2018. In August 2018, the EPA ended the federal response to the matter. The response has now transitioned to the NJDEP site remediation program. The impacted cable was repaired in late September 2017; however, small amounts of residual dielectric fluid believed to be contained within the marina sediment continue to appear on the surface and response actions related to the fluid discharge are ongoing, although at a significantly reduced scale. PSE&G remains concerned about future leaks and potential environmental impacts as a result of reintroduction of fluid back into these lines and has determined that retirement of the affected facilities is appropriate. PSE&G has been unable to reach an agreement with Con Edison and, as a result, in May 2018, PSE&G filed an action at FERC to resolve the matter. FERC dismissed PSE&G’s Complaint against Con Edison in September 2018 and PSE&G has challenged FERC’s decision. Also ongoing is the lawsuit in federal court to determine ultimate responsibility for the costs to address the leak among PSE&G, Con Edison and NADC. In addition, Con Edison filed counter claims against PSE&G and NADC, including seeking injunctive relief and damages. Based on the information currently available and depending on the outcome of the federal court action, PSE&G’s portion of the costs to address the leak may be material; however, PSE&G anticipates that it will recover these costs through regulatory proceedings. Steam Electric Effluent Guidelines In September 2015, the EPA issued a new Effluent Limitation Guidelines Rule (ELG Rule) for steam electric generating units. The rule establishes new best available technology economically achievable (BAT) standards for fly ash transport water, bottom ash transport water, flue gas desulfurization and flue gas mercury control wastewater. Power’s Bridgeport Harbor station and the jointly-owned Keystone and Conemaugh stations, have bottom ash transport water discharges that are regulated under the ELG Rule. Keystone and Conemaugh also have flue gas desulfurization wastewaters regulated by the ELG Rule. Through various orders, the EPA has stayed the compliance dates in the ELG Rule and has announced plans to further revise the requirements and compliance dates of the ELG Rule. Power is unable to determine how this will ultimately impact its compliance requirements or its financial condition and results of operations. Basic Generation Service (BGS) and Basic Gas Supply Service (BGSS) PSE&G obtains its electric supply requirements through the annual New Jersey BGS auctions for two categories of customers who choose not to purchase electric supply from third-party suppliers. The first category, which represents about 80% of PSE&G’s load requirement, is residential and smaller commercial and industrial customers (BGS-Residential Small Commercial Pricing (RSCP)). The second category is larger customers that exceed a BPU-established load (kW) threshold (BGS-Commercial and Industrial Energy Pricing (CIEP)). Pursuant to applicable BPU rules, PSE&G enters into the Supplier Master Agreement with the winners of these BGS auctions following the BPU’s approval of the auction results. PSE&G has entered into contracts with winning BGS suppliers, including Power, to purchase BGS for PSE&G’s load requirements. The winners of the auction (including Power) are responsible for fulfilling all the requirements of a PJM Load-Serving Entity including the provision of capacity, energy, ancillary services, transmission and any other services required by PJM. BGS suppliers assume all volume risk and customer migration risk and must satisfy New Jersey’s renewable portfolio standards. The BGS-CIEP auction is for a one-year supply period from June 1 to May 31 with the BGS-CIEP auction price measured in dollars per MW-day for capacity. The final price for the BGS-CIEP auction year commencing June 1, 2019 is $281.78 per MW-day, replacing the BGS-CIEP auction year price ending May 31, 2019 of $287.76 per MW-day. Energy for BGS-CIEP is priced at hourly PJM locational marginal prices for the contract period. PSE&G contracts for its anticipated BGS-RSCP load on a three-year rolling basis, whereby each year one-third of the load is procured for a three-year period. The contract prices in dollars per MWh for the BGS-RSCP supply, as well as the approximate load, are as follows: Auction Year 2016 2017 2018 2019 36-Month Terms Ending May 2019 May 2020 May 2021 May 2022 (A) Load (MW) 2,800 2,800 2,900 2,800 $ per MWh $96.38 $90.78 $91.77 $98.04 (A) Prices set in the 2019 BGS auction will become effective on June 1, 2019 when the 2016 BGS auction agreements expire. Power seeks to mitigate volatility in its results by contracting in advance for the sale of most of its anticipated electric output as well as its anticipated fuel needs. As part of its objective, Power has entered into contracts to directly supply PSE&G and other New Jersey electric distribution companies with a portion of their respective BGS requirements through the New Jersey BGS auction process, described above. PSE&G has a full-requirements contract with Power to meet the gas supply requirements of PSE&G’s gas customers. Power has entered into hedges for a portion of these anticipated BGSS obligations, as permitted by the BPU. The BPU permits PSE&G to recover the cost of gas hedging up to 115 billion cubic feet or 80% of its residential gas supply annual requirements through the BGSS tariff. Current plans call for Power to hedge on behalf of PSE&G approximately 70 billion cubic feet or 50% of its residential gas supply annual requirements. For additional information, see Note 25. Related-Party Transactions . Minimum Fuel Purchase Requirements Power’s nuclear fuel strategy is to maintain certain levels of uranium and to make periodic purchases to support such levels. As such, the commitments referred to in the following table may include estimated quantities to be purchased that deviate from contractual nominal quantities. Power’s nuclear fuel commitments cover approximately 100% of its estimated uranium, enrichment and fabrication requirements through 2020 and a significant portion through 2021 at Salem, Hope Creek and Peach Bottom. Power has various multi-year contracts for natural gas and firm transportation and storage capacity for natural gas that are primarily used to meet its obligations to PSE&G. When there is excess delivery capacity available beyond the needs of PSE&G’s customers, Power can use the gas to supply its fossil generating stations in New Jersey. Power also has various long-term fuel purchase commitments for coal through 2023 to support its fossil generation stations. As of December 31, 2018 , the total minimum purchase requirements included in these commitments were as follows: Fuel Type Power's Share of Commitments through 2023 Millions Nuclear Fuel Uranium $ 222 Enrichment $ 358 Fabrication $ 167 Natural Gas $ 1,102 Coal $ 429 Pending FERC Matters In June 2015, Transource LLC, a merchant transmission developer, filed a complaint against PJM claiming that PJM wrongfully refused to provide data and a transparent process for evaluating transmission network upgrade requests that the transmission developer had submitted to PJM. Although not named as a respondent, the complaint identifies PSE&G as one of the companies claimed to have been involved. In January 2018, a FERC administrative law judge (ALJ) issued an order generally finding that PJM and transmission owners, including PSE&G, did not engage in wrongful conduct. In addition, the developer’s assertion of an entitlement to monetary damages was expressly denied. However, in a determination disputed by PSE&G, the order found that the PJM process lacked transparency. The judge’s order has been briefed by all parties for additional determinations by FERC. We are unable to predict the outcome of these proceedings. Subsequent to the ALJ decision, PSE&G received requests for information from FERC’s Office of Enforcement concerning a transmission project. PSE&G is complying with these requests and cannot predict the outcome of this matter. Litigation Sewaren 7 Construction In June 2018, a complaint was filed in federal court in Newark, New Jersey against PSEG Fossil LLC, a wholly owned subsidiary of Power, regarding an ongoing dispute with Durr Mechanical Construction, Inc. (Durr), a contractor on the Sewaren 7 project. Among other things, Durr seeks damages of $93 million and alleges that Power withheld money owed to Durr and that Power’s intentional conduct led to the inability of Durr to obtain prospective contracts. Power intends to vigorously defend against these allegations. In December 2018, Durr filed for Chapter 11 bankruptcy in the federal court in the Southern District of New York (SDNY). The SDNY bankruptcy court has allowed the New Jersey litigation to proceed. Power has accrued an amount related to outstanding invoices which does not reflect an assessment of claims and potential counterclaims in this matter. Due to its preliminary nature, Power cannot predict the outcome of this matter. Newark Customer Incident On the morning of July 5, 2018, PSE&G discontinued electricity to the home of a customer residing in Newark because of outstanding arrears on that customer’s account. Subsequent to the discontinuation of electricity, that customer died on the afternoon of July 5th. The family of the customer, who was on hospice care, raised allegations in the media regarding PSE&G’s conduct surrounding the discontinuation and restoration of electricity to the home of the customer, claiming that the discontinuation of electric service prevented the customer from using life sustaining medical equipment. The BPU initiated an investigation into the matter and that investigation is ongoing. In addition, PSE&G received a grand jury subpoena from the Essex County Prosecutor’s Office (ECPO) for records and correspondence between PSE&G and the customer. PSE&G is fully cooperating with the BPU and the ECPO in both proceedings. PSEG cannot predict the outcome of the pending proceedings regarding this incident at this time. The PSEG Board of Directors (PSEG Board) retained outside counsel to conduct an independent investigation of the facts surrounding this incident with the full support and cooperation of management. The independent investigation concluded that the disconnection itself was not improper; however, it did identify issues related to PSE&G’s response once it was notified of the disconnection. The PSEG Board reviewed and considered the findings and conclusions of the investigation and PSE&G’s proposed corrective actions. PSE&G’s progress on implementation of the corrective actions will continue to be overseen by the PSEG Board. Caithness Energy, L.L.C. (Caithness) In August 2018, Caithness, a Long Island power plant developer, filed a complaint in federal district court in the Eastern District of New York against PSEG and PSEG LI alleging violations of state and federal antitrust laws and a claim of intentional interference of prospective business relations. Caithness alleges that PSEG and PSEG LI interfered with LIPA’s consideration of the Caithness proposal for a 750 MW combined cycle generation project that was identified as a finalist for a Request For Proposal issued by LIPA. In addition, Caithness claims that PSEG and PSEG LI induced LIPA to agree to eliminate the proposed project as a potential competitor to other PSEG affiliates with power supply operations. The complaint alleges hundreds of millions of dollars of harm and seeks treble and punitive damages. PSEG intends to vigorously defend against these allegations. Based upon the preliminary nature of this matter, a loss is not considered probable nor is the amount of loss, if any, estimable as of December 31, 2018 . Transource LLC (Transource) In January 2019, Transource filed a complaint against PJM, PSE&G and three other transmission owners in Pennsylvania state court. Transource has sued the transmission owner defendants for fraud and
Power [Member]
Other Commitments [Line Items]
Commitments and Contingent Liabilities	Commitments and Contingent Liabilities Guaranteed Obligations Power’s activities primarily involve the purchase and sale of energy and related products under transportation, physical, financial and forward contracts at fixed and variable prices. These transactions are with numerous counterparties and brokers that may require cash, cash-related instruments or guarantees as a form of collateral. Power has unconditionally guaranteed payments to counterparties by its subsidiaries in commodity-related transactions in order to • support current exposure, interest and other costs on sums due and payable in the ordinary course of business, and • obtain credit. Power is subject to • counterparty collateral calls related to commodity contracts, and • certain creditworthiness standards as guarantor under performance guarantees of its subsidiaries. Under these agreements, guarantees cover lines of credit between entities and are often reciprocal in nature. The exposure between counterparties can move in either direction. In order for Power to incur a liability for the face value of the outstanding guarantees, its subsidiaries would have to • fully utilize the credit granted to them by every counterparty to whom Power has provided a guarantee, and • the net position of the related contracts would have to be “out-of-the-money” (if the contracts are terminated, Power would owe money to the counterparties). Power believes the probability of this result is unlikely. For this reason, Power believes that the current exposure at any point in time is a more meaningful representation of the potential liability under these guarantees. Current exposure consists of the net of accounts receivable and accounts payable and the forward value on open positions, less any collateral posted. Changes in commodity prices can have a material impact on collateral requirements under such contracts, which are posted and received primarily in the form of cash and letters of credit. Power also routinely enters into futures and options transactions for electricity and natural gas as part of its operations. These futures contracts usually require a cash margin deposit with brokers, which can change based on market movement and in accordance with exchange rules. In addition to the guarantees discussed above, Power has also provided payment guarantees to third parties on behalf of its affiliated companies. These guarantees support various other non-commodity related contractual obligations. The following table shows the face value of Power’s outstanding guarantees, current exposure and margin positions as of December 31, 2018 and 2017 . As of December 31, 2018 As of December 31, 2017 Millions Face Value of Outstanding Guarantees $ 1,772 $ 1,701 Exposure under Current Guarantees $ 198 $ 153 Letters of Credit Margin Posted $ 115 $ 103 Letters of Credit Margin Received $ 26 $ 32 Cash Deposited and Received Counterparty Cash Margin Deposited $ — $ — Counterparty Cash Margin Received $ (10 ) $ (1 ) Net Broker Balance Deposited (Received) $ 403 $ 147 Additional Amounts Posted Other Letters of Credit $ 52 $ 61 As part of determining credit exposure, Power nets receivables and payables with the corresponding net fair values of energy contracts. See Note 17. Financial Risk Management Activities for further discussion. In accordance with PSEG’s accounting policy, where it is applicable, cash (received)/deposited is allocated against derivative asset and liability positions with the same counterparty on the face of the Consolidated Balance Sheet. The remaining balances of net cash (received)/deposited after allocation are generally included in Accounts Payable and Receivable, respectively. In addition to amounts for outstanding guarantees, current exposure and margin positions, PSEG and Power have posted letters of credit to support Power’s various other non-energy contractual and environmental obligations. See preceding table. Environmental Matters Passaic River Historic operations of PSEG companies and the operations of hundreds of other companies along the Passaic and Hackensack Rivers are alleged by Federal and State agencies to have discharged substantial contamination into the Passaic River/Newark Bay Complex in violation of various statutes as discussed as follows. Federal Comprehensive Environmental Response, Compensation and Liability Act of 1980 (CERCLA) The U.S. Environmental Protection Agency (EPA) has determined that a 17 -mile stretch of the lower Passaic River from Newark to Clifton, New Jersey is a “Superfund” site under CERCLA and a comprehensive study of the entire 17 miles of the lower Passaic River needed to be performed. PSE&G and certain of its predecessors conducted operations at properties in this area of the Passaic River. The properties included one operating electric generating station (Essex Site), which was transferred to Power, one former generating station and four former manufactured gas plant (MGP) sites. In early 2007, certain Potentially Responsible Parties (PRPs), including PSE&G and Power, formed a Cooperating Parties Group (CPG) and agreed to assume responsibility for conducting a Remedial Investigation and Feasibility Study (RI/FS) of the 17 miles of the lower Passaic River. The CPG has agreed to allocate, on an interim basis, the associated costs of the RI/FS among its members on the basis of a mutually agreed upon formula. For the purpose of this interim allocation, which has been revised as parties have exited the CPG, approximately 7.6 percent of the RI/FS costs are currently deemed attributable to PSE&G’s former MGP sites and approximately 1.9 percent is attributable to Power’s generating stations. These interim allocations are not binding on PSE&G or Power in terms of their respective shares of the costs that will be ultimately required to remediate the 17 miles of the lower Passaic River. PSEG has provided notice to insurers concerning this potential claim. The CPG’s draft FS set forth various alternatives for remediating the lower Passaic River with an estimated cost to remediate the lower 17 miles of the Passaic River ranging from approximately $518 million to $3.2 billion on an undiscounted basis. In March 2016, the EPA released its Record of Decision (ROD) for the EPA’s own Focused Feasibility Study (FFS) which requires the removal of 3.5 million cubic yards of sediment from the Passaic River’s lower 8.3 miles at an estimated cost of $2.3 billion on an undiscounted basis (ROD Remedy). The EPA estimated the total project length to be about 11 years, including a one year period of negotiation with the PRPs, three to four years to design the project and six years for implementation. Occidental Chemical Corporation (OCC), one of the PRPs, has commenced performance of the remedial design required by the ROD Remedy, reserving its right of cost contribution from all other PRPs. In September 2017, the EPA concluded that an Agency-commenced allocation process for the Passaic River’s lower 8.3 miles should include only certain PRPs. The allocation is intended to lead to a consent decree in which certain of the PRPs agree to perform and pay for the remedial action under EPA oversight. Due to delays from the partial federal government shutdown in late 2018 through early 2019, the timeline for completing the allocation process has been delayed. In October 2018, the EPA Region 2 issued a Directive to the CPG instructing the CPG to focus the ongoing RI/FS evaluation on various adaptive management scenarios for remediation of the upper 9 miles of the Passaic River, which approach has been agreed to in concept by the EPA and the CPG. The Directive does not contain estimates for anticipated costs. Adaptive management focuses on removing targeted “hot spots” of contaminated sediments rather than removing all of the Passaic River’s sediments as in a “bank to bank” approach. In a separate matter, two PRPs, Tierra Solutions, Inc. (Tierra) and Maxus Energy Corporation (Maxus), filed for Chapter 11 bankruptcy in Delaware Federal Bankruptcy Court. In June 2018, the trust representing the creditors in this proceeding filed a complaint asserting claims against the current and former parent entities of Tierra and Maxus, among other parties, for up to $14 billion . Any damages awarded may be used to fund, in part, the remediation costs of the lower 8.3 miles of the Passaic River. The creditor trust has reserved its right to file contribution claims against 28 PRPs, including PSEG. This matter is ongoing. In June 2018, OCC filed a complaint in Federal District Court in Newark against various defendants, including PSE&G, seeking cost recovery and contribution under CERCLA for the remediation of the lower 8.3 miles of the Passaic River. The complaint does not quantify damages sought. The Complaint alleges that “no single hazardous substance” is to blame for the contamination of the lower Passaic River and lists the eight Contaminants of Concern (COCs) identified by the EPA in the ROD. OCC alleges PSE&G is responsible for a portion of six of the eight COCs. PSE&G cannot predict the outcome of this matter. Based upon the estimated cost of the ROD Remedy and PSEG’s estimate of PSE&G’s and Power’s shares of that cost, as of December 31, 2018 , PSEG has accrued approximately $57 million . Of this amount, PSE&G has accrued $46 million as an Environmental Costs Liability and a corresponding Regulatory Asset based on its continued ability to recover such costs in its rates. Power has accrued $11 million as an Other Noncurrent Liability with the corresponding O&M Expense recorded in prior years when the liability was accrued. The EPA has broad authority to implement its selected remedy through the ROD and PSEG cannot at this time predict how the implementation of the ROD might impact PSE&G’s and Power’s ultimate liability. Until (i) the RI/FS, which covers the entire 17 miles of the lower Passaic River, is finalized either in whole or in part, (ii) an agreement by the PRPs to perform either the ROD Remedy as issued, or an amended ROD Remedy determined through negotiation or litigation, and an agreed upon remedy for the remaining 8.7 miles of the river, are reached, (iii) PSE&G’s and Power’s respective shares of the costs, both in the aggregate as well as individually, are determined, and (iv) PSE&G’s continued ability to recover the costs in its rates is determined, it is not possible to predict this matter’s ultimate impact on PSEG’s financial statements. It is possible that PSE&G and Power will record additional costs beyond what they have accrued, and that such costs could be material, but PSEG cannot at the current time estimate the amount or range of any additional costs. Natural Resource Damage Claims In 2003, the New Jersey Department of Environmental Protection (NJDEP) directed PSEG, PSE&G and 56 other PRPs to arrange for a natural resource damage assessment and interim compensatory restoration of natural resource injuries along the lower Passaic River and its tributaries pursuant to the New Jersey Spill Compensation and Control Act. The NJDEP alleged that hazardous substances had been discharged from the Essex Site and the Harrison Site. The NJDEP estimated the cost of interim natural resource injury restoration activities along the lower Passaic River at approximately $950 million . In 2007, agencies of the U.S. Department of Commerce and the U.S. Department of the Interior (the Passaic River federal trustees) sent letters to PSE&G and other PRPs inviting participation in an assessment of injuries to natural resources that the agencies intended to perform. In 2008, PSEG and a number of other PRPs agreed to share certain immaterial costs the trustees have incurred and will incur going forward, and to work with the trustees to explore whether some or all of the trustees’ claims can be resolved in a cooperative fashion. That effort is continuing. PSE&G and Power are unable to estimate their respective portions of the possible loss or range of loss related to this matter. Newark Bay Study Area The EPA has established the Newark Bay Study Area, which it defines as Newark Bay and portions of the Hackensack River, the Arthur Kill and the Kill Van Kull. In August 2006, the EPA sent PSEG and 11 other entities notices that it considered each of the entities to be a PRP with respect to contamination in the Study Area. The notice letter requested that the PRPs fund an EPA-approved study in the Newark Bay Study Area. The notice stated the EPA’s belief that hazardous substances were released from sites owned by PSEG companies and located on the Hackensack River, including two electric generating stations (Hudson and Kearny sites) and one former MGP site. PSEG has participated in and partially funded the second phase of this study. Notices to fund the next phase of the study have been received but PSEG has not consented to fund the third phase. PSE&G and Power are unable to estimate their respective portions of the possible loss or range of loss related to this matter. In December 2018, Power completed the sale of the site of the Hudson electric generating station. Power transferred all land rights and structures on the site to a third party purchaser, along with the assumption of the environmental liabilities for the site. MGP Remediation Program PSE&G is working with the NJDEP to assess, investigate and remediate environmental conditions at its former MGP sites. To date, 38 sites requiring some level of remedial action have been identified. Based on its current studies, PSE&G has determined that the estimated cost to remediate all MGP sites to completion could range between $321 million and $366 million on an undiscounted basis through 2021, including its $46 million share for the Passaic River as discussed above. Since no amount within the range is considered to be most likely, PSE&G has recorded a liability of $321 million as of December 31, 2018 . Of this amount, $56 million was recorded in Other Current Liabilities and $265 million was reflected as Environmental Costs in Noncurrent Liabilities. PSE&G has recorded a $321 million Regulatory Asset with respect to these costs. PSE&G periodically updates its studies taking into account any new regulations or new information which could impact future remediation costs and adjusts its recorded liability accordingly. NJDEP, PSEG and EPA representatives have had discussions regarding to what extent sampling in the Passaic River is required to delineate coal tar from MGP sites that abut the Passaic River Superfund site. PSEG cannot determine at this time whether this will have an impact on the Passaic River Superfund remedy. Clean Water Act (CWA) Permit Renewals Pursuant to the Federal Water Pollution Control Act, National Pollutant Discharge Elimination System permits expire within five years of their effective date. In order to renew these permits, but allow a plant to continue to operate, an owner or operator must file a permit application no later than six months prior to expiration of the permit. States with delegated federal authority for this program manage these permits. The NJDEP manages the permits under the New Jersey Pollutant Discharge Elimination System (NJPDES) program. Connecticut and New York also have permits to manage their respective pollutant discharge elimination system programs. In May 2014, the EPA issued a final cooling water intake rule that establishes requirements for the regulation of cooling water intakes at existing power plants and industrial facilities with a design flow of more than two million gallons of water per day. The EPA has structured the rule so that each state Permitting Director will continue to consider renewal permits for existing power facilities on a case by case basis, based on studies related to impingement mortality and entrainment by the facilities seeking renewal permits. Several environmental organizations and certain energy industry groups have filed suit under the CWA and the Endangered Species Act. The cases were consolidated at the Second Circuit, and in July 2018 the Second Circuit upheld the EPA’s final cooling water intake rule. The Court’s decision allows Permitting Directors to continue to issue permits in accordance with the flexible, site-specific provisions of the final rule. In June 2016, the NJDEP issued a final NJPDES permit for Salem. The final permit does not mandate specific service water system modifications, but consistent with Section 316 (b) of the CWA, it requires additional studies and the selection of technology to address impingement for the service water system. In July 2016, the Delaware Riverkeeper Network (Riverkeeper) filed a request challenging the NJDEP’s issuance of the final NJPDES renewal permit for Salem. NJDEP has granted the hearing request, but it has not yet been scheduled. The Riverkeeper’s filing does not change the effective date of the permit. If the Riverkeeper’s challenge were successful, Power may be required to incur additional costs to comply with the CWA. Potential cooling water system modification costs could be material and could adversely impact the economic competitiveness of this facility. State permitting decisions at Bridgeport and possibly New Haven could also have a material impact on Power’s ability to renew permits at its existing larger once-through cooled plants without making significant upgrades to existing intakes and cooling systems. Power is unable to predict the outcome of these permitting decisions and the effect, if any, that they may have on Power’s future capital requirements, financial condition or results of operations. Power is actively engaged with the Connecticut Department of Energy and Environmental Protection (CTDEEP) regarding renewal of the current permit for the cooling water intake structure at Bridgeport Harbor Station Unit 3 (BH3). To address compliance with the EPA’s CWA Section 316(b) final rule, Power has proposed to continue to operate BH3 without making the capital expenditures for modification to the existing intake structure and retire BH3 in 2021, which is four years earlier than the previously estimated useful life ending in 2025. Power is currently awaiting action by the CTDEEP to issue a draft and then a final permit. Power has entered into a Community Environmental Benefit Agreement (CEBA) with the City of Bridgeport, Connecticut and local community organizations. That CEBA provides that Power would retire BH3 early if all of its conditions precedent occur, which include receipt of all final permits to build and operate a proposed new combined cycle generating facility on the same site that BH3 currently operates. Absent those conditions being met, and the permit for the cooling water intake structure referred to above not being issued, Power may seek to operate BH3 through the previously estimated useful life. In February 2016, the proposed new generating facility at Bridgeport Harbor was awarded a capacity obligation. The Connecticut Siting Council issued an order to approve siting Bridgeport Harbor Station Unit 5. Operations are expected to begin in mid-2019. Power’s obligations under the CEBA are being monitored regularly and carried out as needed. Jersey City, New Jersey Subsurface Feeder Cable Matter In October 2016, a discharge of dielectric fluid from subsurface feeder cables located in the Hudson River near Jersey City, New Jersey, was identified and reported to the NJDEP. The feeder cables are located within a subsurface easement granted to PSE&G by the property owners, Newport Associates Development Company (NADC) and Newport Associates Phase I Developer Limited Partnership. The feeder cables are subject to agreements between PSE&G and Consolidated Edison Company of New York, Inc. (Con Edison) and are jointly owned by PSE&G and Con Edison, with PSE&G owning the portion of the cables located in New Jersey and Con Edison owning the portion of the cables located in New York. The NJDEP declared an emergency and an emergency response action was undertaken to investigate, contain, remediate and stop the fluid discharge; to assess, repair and restore the cables to good working order, if feasible; and to restore the property. The regulatory agencies overseeing the emergency response, including the U.S. Coast Guard, the NJDEP and the Army Corps of Engineers, issued multiple notices, orders and directives to the various parties related to this matter and the parties may also be subject to the assessment of civil penalties related to the discharge and response. The U.S. Coast Guard transitioned control of the federal response to the EPA in May 2018. In August 2018, the EPA ended the federal response to the matter. The response has now transitioned to the NJDEP site remediation program. The impacted cable was repaired in late September 2017; however, small amounts of residual dielectric fluid believed to be contained within the marina sediment continue to appear on the surface and response actions related to the fluid discharge are ongoing, although at a significantly reduced scale. PSE&G remains concerned about future leaks and potential environmental impacts as a result of reintroduction of fluid back into these lines and has determined that retirement of the affected facilities is appropriate. PSE&G has been unable to reach an agreement with Con Edison and, as a result, in May 2018, PSE&G filed an action at FERC to resolve the matter. FERC dismissed PSE&G’s Complaint against Con Edison in September 2018 and PSE&G has challenged FERC’s decision. Also ongoing is the lawsuit in federal court to determine ultimate responsibility for the costs to address the leak among PSE&G, Con Edison and NADC. In addition, Con Edison filed counter claims against PSE&G and NADC, including seeking injunctive relief and damages. Based on the information currently available and depending on the outcome of the federal court action, PSE&G’s portion of the costs to address the leak may be material; however, PSE&G anticipates that it will recover these costs through regulatory proceedings. Steam Electric Effluent Guidelines In September 2015, the EPA issued a new Effluent Limitation Guidelines Rule (ELG Rule) for steam electric generating units. The rule establishes new best available technology economically achievable (BAT) standards for fly ash transport water, bottom ash transport water, flue gas desulfurization and flue gas mercury control wastewater. Power’s Bridgeport Harbor station and the jointly-owned Keystone and Conemaugh stations, have bottom ash transport water discharges that are regulated under the ELG Rule. Keystone and Conemaugh also have flue gas desulfurization wastewaters regulated by the ELG Rule. Through various orders, the EPA has stayed the compliance dates in the ELG Rule and has announced plans to further revise the requirements and compliance dates of the ELG Rule. Power is unable to determine how this will ultimately impact its compliance requirements or its financial condition and results of operations. Basic Generation Service (BGS) and Basic Gas Supply Service (BGSS) PSE&G obtains its electric supply requirements through the annual New Jersey BGS auctions for two categories of customers who choose not to purchase electric supply from third-party suppliers. The first category, which represents about 80% of PSE&G’s load requirement, is residential and smaller commercial and industrial customers (BGS-Residential Small Commercial Pricing (RSCP)). The second category is larger customers that exceed a BPU-established load (kW) threshold (BGS-Commercial and Industrial Energy Pricing (CIEP)). Pursuant to applicable BPU rules, PSE&G enters into the Supplier Master Agreement with the winners of these BGS auctions following the BPU’s approval of the auction results. PSE&G has entered into contracts with winning BGS suppliers, including Power, to purchase BGS for PSE&G’s load requirements. The winners of the auction (including Power) are responsible for fulfilling all the requirements of a PJM Load-Serving Entity including the provision of capacity, energy, ancillary services, transmission and any other services required by PJM. BGS suppliers assume all volume risk and customer migration risk and must satisfy New Jersey’s renewable portfolio standards. The BGS-CIEP auction is for a one-year supply period from June 1 to May 31 with the BGS-CIEP auction price measured in dollars per MW-day for capacity. The final price for the BGS-CIEP auction year commencing June 1, 2019 is $281.78 per MW-day, replacing the BGS-CIEP auction year price ending May 31, 2019 of $287.76 per MW-day. Energy for BGS-CIEP is priced at hourly PJM locational marginal prices for the contract period. PSE&G contracts for its anticipated BGS-RSCP load on a three-year rolling basis, whereby each year one-third of the load is procured for a three-year period. The contract prices in dollars per MWh for the BGS-RSCP supply, as well as the approximate load, are as follows: Auction Year 2016 2017 2018 2019 36-Month Terms Ending May 2019 May 2020 May 2021 May 2022 (A) Load (MW) 2,800 2,800 2,900 2,800 $ per MWh $96.38 $90.78 $91.77 $98.04 (A) Prices set in the 2019 BGS auction will become effective on June 1, 2019 when the 2016 BGS auction agreements expire. Power seeks to mitigate volatility in its results by contracting in advance for the sale of most of its anticipated electric output as well as its anticipated fuel needs. As part of its objective, Power has entered into contracts to directly supply PSE&G and other New Jersey electric distribution companies with a portion of their respective BGS requirements through the New Jersey BGS auction process, described above. PSE&G has a full-requirements contract with Power to meet the gas supply requirements of PSE&G’s gas customers. Power has entered into hedges for a portion of these anticipated BGSS obligations, as permitted by the BPU. The BPU permits PSE&G to recover the cost of gas hedging up to 115 billion cubic feet or 80% of its residential gas supply annual requirements through the BGSS tariff. Current plans call for Power to hedge on behalf of PSE&G approximately 70 billion cubic feet or 50% of its residential gas supply annual requirements. For additional information, see Note 25. Related-Party Transactions . Minimum Fuel Purchase Requirements Power’s nuclear fuel strategy is to maintain certain levels of uranium and to make periodic purchases to support such levels. As such, the commitments referred to in the following table may include estimated quantities to be purchased that deviate from contractual nominal quantities. Power’s nuclear fuel commitments cover approximately 100% of its estimated uranium, enrichment and fabrication requirements through 2020 and a significant portion through 2021 at Salem, Hope Creek and Peach Bottom. Power has various multi-year contracts for natural gas and firm transportation and storage capacity for natural gas that are primarily used to meet its obligations to PSE&G. When there is excess delivery capacity available beyond the needs of PSE&G’s customers, Power can use the gas to supply its fossil generating stations in New Jersey. Power also has various long-term fuel purchase commitments for coal through 2023 to support its fossil generation stations. As of December 31, 2018 , the total minimum purchase requirements included in these commitments were as follows: Fuel Type Power's Share of Commitments through 2023 Millions Nuclear Fuel Uranium $ 222 Enrichment $ 358 Fabrication $ 167 Natural Gas $ 1,102 Coal $ 429 Pending FERC Matters In June 2015, Transource LLC, a merchant transmission developer, filed a complaint against PJM claiming that PJM wrongfully refused to provide data and a transparent process for evaluating transmission network upgrade requests that the transmission developer had submitted to PJM. Although not named as a respondent, the complaint identifies PSE&G as one of the companies claimed to have been involved. In January 2018, a FERC administrative law judge (ALJ) issued an order generally finding that PJM and transmission owners, including PSE&G, did not engage in wrongful conduct. In addition, the developer’s assertion of an entitlement to monetary damages was expressly denied. However, in a determination disputed by PSE&G, the order found that the PJM process lacked transparency. The judge’s order has been briefed by all parties for additional determinations by FERC. We are unable to predict the outcome of these proceedings. Subsequent to the ALJ decision, PSE&G received requests for information from FERC’s Office of Enforcement concerning a transmission project. PSE&G is complying with these requests and cannot predict the outcome of this matter. Litigation Sewaren 7 Construction In June 2018, a complaint was filed in federal court in Newark, New Jersey against PSEG Fossil LLC, a wholly owned subsidiary of Power, regarding an ongoing dispute with Durr Mechanical Construction, Inc. (Durr), a contractor on the Sewaren 7 project. Among other things, Durr seeks damages of $93 million and alleges that Power withheld money owed to Durr and that Power’s intentional conduct led to the inability of Durr to obtain prospective contracts. Power intends to vigorously defend against these allegations. In December 2018, Durr filed for Chapter 11 bankruptcy in the federal court in the Southern District of New York (SDNY). The SDNY bankruptcy court has allowed the New Jersey litigation to proceed. Power has accrued an amount related to outstanding invoices which does not reflect an assessment of claims and potential counterclaims in this matter. Due to its preliminary nature, Power cannot predict the outcome of this matter. Newark Customer Incident On the morning of July 5, 2018, PSE&G discontinued electricity to the home of a customer residing in Newark because of outstanding arrears on that customer’s account. Subsequent to the discontinuation of electricity, that customer died on the afternoon of July 5th. The family of the customer, who was on hospice care, raised allegations in the media regarding PSE&G’s conduct surrounding the discontinuation and restoration of electricity to the home of the customer, claiming that the discontinuation of electric service prevented the customer from using life sustaining medical equipment. The BPU initiated an investigation into the matter and that investigation is ongoing. In addition, PSE&G received a grand jury subpoena from the Essex County Prosecutor’s Office (ECPO) for records and correspondence between PSE&G and the customer. PSE&G is fully cooperating with the BPU and the ECPO in both proceedings. PSEG cannot predict the outcome of the pending proceedings regarding this incident at this time. The PSEG Board of Directors (PSEG Board) retained outside counsel to conduct an independent investigation of the facts surrounding this incident with the full support and cooperation of management. The independent investigation concluded that the disconnection itself was not improper; however, it did identify issues related to PSE&G’s response once it was notified of the disconnection. The PSEG Board reviewed and considered the findings and conclusions of the investigation and PSE&G’s proposed corrective actions. PSE&G’s progress on implementation of the corrective actions will continue to be overseen by the PSEG Board. Caithness Energy, L.L.C. (Caithness) In August 2018, Caithness, a Long Island power plant developer, filed a complaint in federal district court in the Eastern District of New York against PSEG and PSEG LI alleging violations of state and federal antitrust laws and a claim of intentional interference of prospective business relations. Caithness alleges that PSEG and PSEG LI interfered with LIPA’s consideration of the Caithness proposal for a 750 MW combined cycle generation project that was identified as a finalist for a Request For Proposal issued by LIPA. In addition, Caithness claims that PSEG and PSEG LI induced LIPA to agree to eliminate the proposed project as a potential competitor to other PSEG affiliates with power supply operations. The complaint alleges hundreds of millions of dollars of harm and seeks treble and punitive damages. PSEG intends to vigorously defend against these allegations. Based upon the preliminary nature of this matter, a loss is not considered probable nor is the amount of loss, if any, estimable as of December 31, 2018 . Transource LLC (Transource) In January 2019, Transource filed a complaint against PJM, PSE&G and three other transmission owners in Pennsylvania state court. Transource has sued the transmission owner defendants for fraud and

Debt and Credit Facilities

Debt and Credit Facilities	12 Months Ended
	Dec. 31, 2018
Debt Instrument [Line Items]
Schedule Of Consolidated Debt	Debt and Credit Facilities Long-Term Debt As of December 31, Maturity 2018 2017 Millions PSEG Term Loan: Variable 2019 $ 350 $ 700 Variable 2020 700 — Total Term Loan 1,050 700 Senior Notes: 1.60% 2019 400 400 2.00% 2021 300 300 2.65% 2022 700 700 Total Senior Notes 1,400 1,400 Principal Amount Outstanding 2,450 2,100 Amounts Due Within One Year (750 ) — Net Unamortized Discount and Debt Issuance Costs (7 ) (9 ) Total Long-Term Debt of PSEG $ 1,693 $ 2,091 ` As of December 31, Maturity 2018 2017 Millions PSE&G First and Refunding Mortgage Bonds (A): 9.25% 2021 $ 134 $ 134 8.00% 2037 7 7 5.00% 2037 8 8 Total First and Refunding Mortgage Bonds 149 149 Medium-Term Notes (MTNs) (A): 5.30% 2018 — 400 2.30% 2018 — 350 1.80% 2019 250 250 2.00% 2019 250 250 3.50% 2020 250 250 7.04% 2020 9 9 1.90% 2021 300 300 2.38% 2023 500 500 3.25% 2023 325 — 3.75% 2024 250 250 3.15% 2024 250 250 3.05% 2024 250 250 3.00% 2025 350 350 2.25% 2026 425 425 3.00% 2027 425 425 3.70% 2028 375 — 3.65% 2028 325 — 5.25% 2035 250 250 5.70% 2036 250 250 5.80% 2037 350 350 5.38% 2039 250 250 5.50% 2040 300 300 3.95% 2042 450 450 3.65% 2042 350 350 3.80% 2043 400 400 4.00% 2044 250 250 4.05% 2045 250 250 4.15% 2045 250 250 3.80% 2046 550 550 3.60% 2047 350 350 4.05% 2048 325 — Total MTNs 9,109 8,509 Principal Amount Outstanding 9,258 8,658 Amounts Due Within One Year (500 ) (750 ) Net Unamortized Discount and Debt Issuance Costs (74 ) (67 ) Total Long-Term Debt of PSE&G $ 8,684 $ 7,841 As of December 31, Maturity 2018 2017 Millions Power Senior Notes: 2.45% 2018 $ — $ 250 5.13% 2020 406 406 3.00% 2021 700 700 4.15% 2021 250 250 3.85% 2023 700 — 4.30% 2023 250 250 8.63% 2031 500 500 Total Senior Notes 2,806 2,356 Pollution Control Notes: Floating Rate (B) 2019 44 44 Total Pollution Control Notes 44 44 Principal Amount Outstanding 2,850 2,400 Amounts Due Within One Year (44 ) (250 ) Net Unamortized Discount and Debt Issuance Costs (15 ) (14 ) Total Long-Term Debt of Power $ 2,791 $ 2,136 (A) Secured by essentially all property of PSE&G pursuant to its First and Refunding Mortgage. (B) The Pennsylvania Economic Development Authority (PEDFA) bond that is serviced and secured by Power Pollution Control Notes is a variable rate bond that is in weekly reset mode. Long-Term Debt Maturities The aggregate principal amounts of maturities for each of the five years following December 31, 2018 are as follows: Year PSEG PSE&G Power Total 2019 $ 750 $ 500 $ 44 $ 1,294 2020 700 259 406 1,365 2021 300 434 950 1,684 2022 700 — — 700 2023 — 825 950 1,775 Thereafter — 7,240 500 7,740 Total $ 2,450 $ 9,258 $ 2,850 $ 14,558 Long-Term Debt Financing Transactions During 2018 , PSEG and its subsidiaries had the following Long-Term Debt issuances, maturities and redemptions: PSEG • entered into an agreement for a new term loan maturing November 2020 . The term loan has a balance of $700 million at an interest rate of 1 month LIBOR + 0.60% and can be terminated at any time without penalty, and • redeemed $350 million of a $700 million term loan at an interest rate of 1 month LIBOR + 0.80% maturing June 2019 . PSE&G • issued $375 million of 3.70% Secured Medium-Term Notes, Series M, due May 2028 , • issued $325 million of 4.05% Secured Medium-Term Notes, Series M, due May 2048 , • issued $325 million of 3.25% Secured Medium-Term Notes, Series M, due September 2023 , • issued $325 million of 3.65% Secured Medium-Term Notes, Series M, due September 2028 , • retired $400 million of 5.30% Medium-Term Notes at maturity, and • retired $350 million of 2.30% Medium-Term Notes at maturity. Power • issued $700 million of 3.85% Senior Notes due June 2023 , and • retired $250 million of 2.45% Senior Notes at maturity. 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. The commitments under the $4.2 billion credit facilities are provided by a diverse bank group. As of December 31, 2018 , the total available credit capacity was $3.0 billion . As of December 31, 2018 , no single institution represented more than 9% of the total commitments in the credit facilities. As of December 31, 2018 , the total credit capacity was in excess of the anticipated maximum liquidity requirements over PSEG’s 12-month planning horizon. Each of the credit facilities is restricted as to availability and use to the specific companies as listed in the following table; however, if necessary, the PSEG facilities can also be used to support our subsidiaries’ liquidity needs. The total credit facilities and available liquidity as of December 31, 2018 were as follows: As of December 31, 2018 Company/Facility Total Facility Usage Available Liquidity Expiration Date Primary Purpose Millions PSEG 5-year Credit Facilities (A) $ 1,500 $ 759 $ 741 Mar 2022 Commercial Paper Support/Funding/Letters of Credit Total PSEG $ 1,500 $ 759 $ 741 PSE&G 5-year Credit Facility (A) $ 600 $ 288 $ 312 Mar 2022 Commercial Paper Support/Funding/Letters of Credit Total PSE&G $ 600 $ 288 $ 312 Power 3-year Letter of Credit Facilities $ 200 $ 114 $ 86 Sept 2021 Letters of Credit 5-year Credit Facilities 1,900 40 1,860 Mar 2022 Funding/Letters of Credit Total Power $ 2,100 $ 154 $ 1,946 Total $ 4,200 $ 1,201 $ 2,999 (A) The primary use of PSEG’s and PSE&G’s credit facilities is to support their respective Commercial Paper Programs under which as of December 31, 2018 , PSEG had $744 million outstanding at a weighted average interest rate of 2.95% . PSE&G had $272 million outstanding at a weighted average interest rate of 2.96% under its Commercial Paper Program as of December 31, 2018 . Fair Value of Debt The estimated fair values, carrying amounts and methods used to determine fair value of long-term debt as of December 31, 2018 and 2017 are included in the following table and accompanying notes as of December 31, 2018 and 2017 . See Note 18. Fair Value Measurements for more information on fair value guidance and the hierarchy that prioritizes the inputs to fair value measurements into three levels. December 31, 2018 December 31, 2017 Carrying Amount Fair Value Carrying Amount Fair Value Millions Long-Term Debt: PSEG (A) (B) $ 2,443 $ 2,397 $ 2,091 $ 2,081 PSE&G (B) 9,184 9,374 8,591 9,322 Power (B) 2,835 2,996 2,386 2,659 Total Long-Term Debt $ 14,462 $ 14,767 $ 13,068 $ 14,062 (A) As of December 31, 2018 and 2017 , fair value includes floating rate term loans of $1,050 million and $700 million , respectively. The fair value of the term loan debt (Level 2 measurement) approximates the carrying value because the interest payments are based on LIBOR rates that are reset monthly and the debt is redeemable at face value by PSEG at any time. (B) Given that these bonds do not trade actively, the fair value amounts of taxable debt securities (primarily Level 2 measurements) are generally determined by a valuation model that is based on a conventional discounted cash flow methodology and utilizes assumptions of current market pricing curves. In order to incorporate the credit risk into the discount rates, pricing 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.
PSE&G [Member]
Debt Instrument [Line Items]
Schedule Of Consolidated Debt	Debt and Credit Facilities Long-Term Debt As of December 31, Maturity 2018 2017 Millions PSEG Term Loan: Variable 2019 $ 350 $ 700 Variable 2020 700 — Total Term Loan 1,050 700 Senior Notes: 1.60% 2019 400 400 2.00% 2021 300 300 2.65% 2022 700 700 Total Senior Notes 1,400 1,400 Principal Amount Outstanding 2,450 2,100 Amounts Due Within One Year (750 ) — Net Unamortized Discount and Debt Issuance Costs (7 ) (9 ) Total Long-Term Debt of PSEG $ 1,693 $ 2,091 ` As of December 31, Maturity 2018 2017 Millions PSE&G First and Refunding Mortgage Bonds (A): 9.25% 2021 $ 134 $ 134 8.00% 2037 7 7 5.00% 2037 8 8 Total First and Refunding Mortgage Bonds 149 149 Medium-Term Notes (MTNs) (A): 5.30% 2018 — 400 2.30% 2018 — 350 1.80% 2019 250 250 2.00% 2019 250 250 3.50% 2020 250 250 7.04% 2020 9 9 1.90% 2021 300 300 2.38% 2023 500 500 3.25% 2023 325 — 3.75% 2024 250 250 3.15% 2024 250 250 3.05% 2024 250 250 3.00% 2025 350 350 2.25% 2026 425 425 3.00% 2027 425 425 3.70% 2028 375 — 3.65% 2028 325 — 5.25% 2035 250 250 5.70% 2036 250 250 5.80% 2037 350 350 5.38% 2039 250 250 5.50% 2040 300 300 3.95% 2042 450 450 3.65% 2042 350 350 3.80% 2043 400 400 4.00% 2044 250 250 4.05% 2045 250 250 4.15% 2045 250 250 3.80% 2046 550 550 3.60% 2047 350 350 4.05% 2048 325 — Total MTNs 9,109 8,509 Principal Amount Outstanding 9,258 8,658 Amounts Due Within One Year (500 ) (750 ) Net Unamortized Discount and Debt Issuance Costs (74 ) (67 ) Total Long-Term Debt of PSE&G $ 8,684 $ 7,841 As of December 31, Maturity 2018 2017 Millions Power Senior Notes: 2.45% 2018 $ — $ 250 5.13% 2020 406 406 3.00% 2021 700 700 4.15% 2021 250 250 3.85% 2023 700 — 4.30% 2023 250 250 8.63% 2031 500 500 Total Senior Notes 2,806 2,356 Pollution Control Notes: Floating Rate (B) 2019 44 44 Total Pollution Control Notes 44 44 Principal Amount Outstanding 2,850 2,400 Amounts Due Within One Year (44 ) (250 ) Net Unamortized Discount and Debt Issuance Costs (15 ) (14 ) Total Long-Term Debt of Power $ 2,791 $ 2,136 (A) Secured by essentially all property of PSE&G pursuant to its First and Refunding Mortgage. (B) The Pennsylvania Economic Development Authority (PEDFA) bond that is serviced and secured by Power Pollution Control Notes is a variable rate bond that is in weekly reset mode. Long-Term Debt Maturities The aggregate principal amounts of maturities for each of the five years following December 31, 2018 are as follows: Year PSEG PSE&G Power Total 2019 $ 750 $ 500 $ 44 $ 1,294 2020 700 259 406 1,365 2021 300 434 950 1,684 2022 700 — — 700 2023 — 825 950 1,775 Thereafter — 7,240 500 7,740 Total $ 2,450 $ 9,258 $ 2,850 $ 14,558 Long-Term Debt Financing Transactions During 2018 , PSEG and its subsidiaries had the following Long-Term Debt issuances, maturities and redemptions: PSEG • entered into an agreement for a new term loan maturing November 2020 . The term loan has a balance of $700 million at an interest rate of 1 month LIBOR + 0.60% and can be terminated at any time without penalty, and • redeemed $350 million of a $700 million term loan at an interest rate of 1 month LIBOR + 0.80% maturing June 2019 . PSE&G • issued $375 million of 3.70% Secured Medium-Term Notes, Series M, due May 2028 , • issued $325 million of 4.05% Secured Medium-Term Notes, Series M, due May 2048 , • issued $325 million of 3.25% Secured Medium-Term Notes, Series M, due September 2023 , • issued $325 million of 3.65% Secured Medium-Term Notes, Series M, due September 2028 , • retired $400 million of 5.30% Medium-Term Notes at maturity, and • retired $350 million of 2.30% Medium-Term Notes at maturity. Power • issued $700 million of 3.85% Senior Notes due June 2023 , and • retired $250 million of 2.45% Senior Notes at maturity. 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. The commitments under the $4.2 billion credit facilities are provided by a diverse bank group. As of December 31, 2018 , the total available credit capacity was $3.0 billion . As of December 31, 2018 , no single institution represented more than 9% of the total commitments in the credit facilities. As of December 31, 2018 , the total credit capacity was in excess of the anticipated maximum liquidity requirements over PSEG’s 12-month planning horizon. Each of the credit facilities is restricted as to availability and use to the specific companies as listed in the following table; however, if necessary, the PSEG facilities can also be used to support our subsidiaries’ liquidity needs. The total credit facilities and available liquidity as of December 31, 2018 were as follows: As of December 31, 2018 Company/Facility Total Facility Usage Available Liquidity Expiration Date Primary Purpose Millions PSEG 5-year Credit Facilities (A) $ 1,500 $ 759 $ 741 Mar 2022 Commercial Paper Support/Funding/Letters of Credit Total PSEG $ 1,500 $ 759 $ 741 PSE&G 5-year Credit Facility (A) $ 600 $ 288 $ 312 Mar 2022 Commercial Paper Support/Funding/Letters of Credit Total PSE&G $ 600 $ 288 $ 312 Power 3-year Letter of Credit Facilities $ 200 $ 114 $ 86 Sept 2021 Letters of Credit 5-year Credit Facilities 1,900 40 1,860 Mar 2022 Funding/Letters of Credit Total Power $ 2,100 $ 154 $ 1,946 Total $ 4,200 $ 1,201 $ 2,999 (A) The primary use of PSEG’s and PSE&G’s credit facilities is to support their respective Commercial Paper Programs under which as of December 31, 2018 , PSEG had $744 million outstanding at a weighted average interest rate of 2.95% . PSE&G had $272 million outstanding at a weighted average interest rate of 2.96% under its Commercial Paper Program as of December 31, 2018 . Fair Value of Debt The estimated fair values, carrying amounts and methods used to determine fair value of long-term debt as of December 31, 2018 and 2017 are included in the following table and accompanying notes as of December 31, 2018 and 2017 . See Note 18. Fair Value Measurements for more information on fair value guidance and the hierarchy that prioritizes the inputs to fair value measurements into three levels. December 31, 2018 December 31, 2017 Carrying Amount Fair Value Carrying Amount Fair Value Millions Long-Term Debt: PSEG (A) (B) $ 2,443 $ 2,397 $ 2,091 $ 2,081 PSE&G (B) 9,184 9,374 8,591 9,322 Power (B) 2,835 2,996 2,386 2,659 Total Long-Term Debt $ 14,462 $ 14,767 $ 13,068 $ 14,062 (A) As of December 31, 2018 and 2017 , fair value includes floating rate term loans of $1,050 million and $700 million , respectively. The fair value of the term loan debt (Level 2 measurement) approximates the carrying value because the interest payments are based on LIBOR rates that are reset monthly and the debt is redeemable at face value by PSEG at any time. (B) Given that these bonds do not trade actively, the fair value amounts of taxable debt securities (primarily Level 2 measurements) are generally determined by a valuation model that is based on a conventional discounted cash flow methodology and utilizes assumptions of current market pricing curves. In order to incorporate the credit risk into the discount rates, pricing 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.
Power [Member]
Debt Instrument [Line Items]
Schedule Of Consolidated Debt	Debt and Credit Facilities Long-Term Debt As of December 31, Maturity 2018 2017 Millions PSEG Term Loan: Variable 2019 $ 350 $ 700 Variable 2020 700 — Total Term Loan 1,050 700 Senior Notes: 1.60% 2019 400 400 2.00% 2021 300 300 2.65% 2022 700 700 Total Senior Notes 1,400 1,400 Principal Amount Outstanding 2,450 2,100 Amounts Due Within One Year (750 ) — Net Unamortized Discount and Debt Issuance Costs (7 ) (9 ) Total Long-Term Debt of PSEG $ 1,693 $ 2,091 ` As of December 31, Maturity 2018 2017 Millions PSE&G First and Refunding Mortgage Bonds (A): 9.25% 2021 $ 134 $ 134 8.00% 2037 7 7 5.00% 2037 8 8 Total First and Refunding Mortgage Bonds 149 149 Medium-Term Notes (MTNs) (A): 5.30% 2018 — 400 2.30% 2018 — 350 1.80% 2019 250 250 2.00% 2019 250 250 3.50% 2020 250 250 7.04% 2020 9 9 1.90% 2021 300 300 2.38% 2023 500 500 3.25% 2023 325 — 3.75% 2024 250 250 3.15% 2024 250 250 3.05% 2024 250 250 3.00% 2025 350 350 2.25% 2026 425 425 3.00% 2027 425 425 3.70% 2028 375 — 3.65% 2028 325 — 5.25% 2035 250 250 5.70% 2036 250 250 5.80% 2037 350 350 5.38% 2039 250 250 5.50% 2040 300 300 3.95% 2042 450 450 3.65% 2042 350 350 3.80% 2043 400 400 4.00% 2044 250 250 4.05% 2045 250 250 4.15% 2045 250 250 3.80% 2046 550 550 3.60% 2047 350 350 4.05% 2048 325 — Total MTNs 9,109 8,509 Principal Amount Outstanding 9,258 8,658 Amounts Due Within One Year (500 ) (750 ) Net Unamortized Discount and Debt Issuance Costs (74 ) (67 ) Total Long-Term Debt of PSE&G $ 8,684 $ 7,841 As of December 31, Maturity 2018 2017 Millions Power Senior Notes: 2.45% 2018 $ — $ 250 5.13% 2020 406 406 3.00% 2021 700 700 4.15% 2021 250 250 3.85% 2023 700 — 4.30% 2023 250 250 8.63% 2031 500 500 Total Senior Notes 2,806 2,356 Pollution Control Notes: Floating Rate (B) 2019 44 44 Total Pollution Control Notes 44 44 Principal Amount Outstanding 2,850 2,400 Amounts Due Within One Year (44 ) (250 ) Net Unamortized Discount and Debt Issuance Costs (15 ) (14 ) Total Long-Term Debt of Power $ 2,791 $ 2,136 (A) Secured by essentially all property of PSE&G pursuant to its First and Refunding Mortgage. (B) The Pennsylvania Economic Development Authority (PEDFA) bond that is serviced and secured by Power Pollution Control Notes is a variable rate bond that is in weekly reset mode. Long-Term Debt Maturities The aggregate principal amounts of maturities for each of the five years following December 31, 2018 are as follows: Year PSEG PSE&G Power Total 2019 $ 750 $ 500 $ 44 $ 1,294 2020 700 259 406 1,365 2021 300 434 950 1,684 2022 700 — — 700 2023 — 825 950 1,775 Thereafter — 7,240 500 7,740 Total $ 2,450 $ 9,258 $ 2,850 $ 14,558 Long-Term Debt Financing Transactions During 2018 , PSEG and its subsidiaries had the following Long-Term Debt issuances, maturities and redemptions: PSEG • entered into an agreement for a new term loan maturing November 2020 . The term loan has a balance of $700 million at an interest rate of 1 month LIBOR + 0.60% and can be terminated at any time without penalty, and • redeemed $350 million of a $700 million term loan at an interest rate of 1 month LIBOR + 0.80% maturing June 2019 . PSE&G • issued $375 million of 3.70% Secured Medium-Term Notes, Series M, due May 2028 , • issued $325 million of 4.05% Secured Medium-Term Notes, Series M, due May 2048 , • issued $325 million of 3.25% Secured Medium-Term Notes, Series M, due September 2023 , • issued $325 million of 3.65% Secured Medium-Term Notes, Series M, due September 2028 , • retired $400 million of 5.30% Medium-Term Notes at maturity, and • retired $350 million of 2.30% Medium-Term Notes at maturity. Power • issued $700 million of 3.85% Senior Notes due June 2023 , and • retired $250 million of 2.45% Senior Notes at maturity. 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. The commitments under the $4.2 billion credit facilities are provided by a diverse bank group. As of December 31, 2018 , the total available credit capacity was $3.0 billion . As of December 31, 2018 , no single institution represented more than 9% of the total commitments in the credit facilities. As of December 31, 2018 , the total credit capacity was in excess of the anticipated maximum liquidity requirements over PSEG’s 12-month planning horizon. Each of the credit facilities is restricted as to availability and use to the specific companies as listed in the following table; however, if necessary, the PSEG facilities can also be used to support our subsidiaries’ liquidity needs. The total credit facilities and available liquidity as of December 31, 2018 were as follows: As of December 31, 2018 Company/Facility Total Facility Usage Available Liquidity Expiration Date Primary Purpose Millions PSEG 5-year Credit Facilities (A) $ 1,500 $ 759 $ 741 Mar 2022 Commercial Paper Support/Funding/Letters of Credit Total PSEG $ 1,500 $ 759 $ 741 PSE&G 5-year Credit Facility (A) $ 600 $ 288 $ 312 Mar 2022 Commercial Paper Support/Funding/Letters of Credit Total PSE&G $ 600 $ 288 $ 312 Power 3-year Letter of Credit Facilities $ 200 $ 114 $ 86 Sept 2021 Letters of Credit 5-year Credit Facilities 1,900 40 1,860 Mar 2022 Funding/Letters of Credit Total Power $ 2,100 $ 154 $ 1,946 Total $ 4,200 $ 1,201 $ 2,999 (A) The primary use of PSEG’s and PSE&G’s credit facilities is to support their respective Commercial Paper Programs under which as of December 31, 2018 , PSEG had $744 million outstanding at a weighted average interest rate of 2.95% . PSE&G had $272 million outstanding at a weighted average interest rate of 2.96% under its Commercial Paper Program as of December 31, 2018 . Fair Value of Debt The estimated fair values, carrying amounts and methods used to determine fair value of long-term debt as of December 31, 2018 and 2017 are included in the following table and accompanying notes as of December 31, 2018 and 2017 . See Note 18. Fair Value Measurements for more information on fair value guidance and the hierarchy that prioritizes the inputs to fair value measurements into three levels. December 31, 2018 December 31, 2017 Carrying Amount Fair Value Carrying Amount Fair Value Millions Long-Term Debt: PSEG (A) (B) $ 2,443 $ 2,397 $ 2,091 $ 2,081 PSE&G (B) 9,184 9,374 8,591 9,322 Power (B) 2,835 2,996 2,386 2,659 Total Long-Term Debt $ 14,462 $ 14,767 $ 13,068 $ 14,062 (A) As of December 31, 2018 and 2017 , fair value includes floating rate term loans of $1,050 million and $700 million , respectively. The fair value of the term loan debt (Level 2 measurement) approximates the carrying value because the interest payments are based on LIBOR rates that are reset monthly and the debt is redeemable at face value by PSEG at any time. (B) Given that these bonds do not trade actively, the fair value amounts of taxable debt securities (primarily Level 2 measurements) are generally determined by a valuation model that is based on a conventional discounted cash flow methodology and utilizes assumptions of current market pricing curves. In order to incorporate the credit risk into the discount rates, pricing 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.

Schedule Of Consolidated Capita

Schedule Of Consolidated Capital Stock	12 Months Ended
	Dec. 31, 2018
Class of Stock [Line Items]
Schedule of Consolidated Capital Stock	Schedule of Consolidated Capital Stock As of December 31, Outstanding Shares Book Value 2018 2017 2018 2017 Millions PSEG Common Stock (no par value) (A) Authorized 1,000 shares 504 505 $ 4,172 $ 4,198 (A) PSEG did not issue any new shares under the Dividend Reinvestment and Stock Purchase Plan (DRASPP) or the Employee Stock Purchase Plan (ESPP) in 2018 or 2017 . As of December 31, 2018 , PSE&G had an aggregate of 7.5 million shares of $100 par value and 10 million shares of $25 par value Cumulative Preferred Stock, which were authorized and unissued and which, upon issuance, may or may not provide for mandatory sinking fund redemption.
PSE&G [Member]
Class of Stock [Line Items]
Schedule of Consolidated Capital Stock	Schedule of Consolidated Capital Stock As of December 31, Outstanding Shares Book Value 2018 2017 2018 2017 Millions PSEG Common Stock (no par value) (A) Authorized 1,000 shares 504 505 $ 4,172 $ 4,198 (A) PSEG did not issue any new shares under the Dividend Reinvestment and Stock Purchase Plan (DRASPP) or the Employee Stock Purchase Plan (ESPP) in 2018 or 2017 . As of December 31, 2018 , PSE&G had an aggregate of 7.5 million shares of $100 par value and 10 million shares of $25 par value Cumulative Preferred Stock, which were authorized and unissued and which, upon issuance, may or may not provide for mandatory sinking fund redemption.
Power [Member]
Class of Stock [Line Items]
Schedule of Consolidated Capital Stock	Schedule of Consolidated Capital Stock As of December 31, Outstanding Shares Book Value 2018 2017 2018 2017 Millions PSEG Common Stock (no par value) (A) Authorized 1,000 shares 504 505 $ 4,172 $ 4,198 (A) PSEG did not issue any new shares under the Dividend Reinvestment and Stock Purchase Plan (DRASPP) or the Employee Stock Purchase Plan (ESPP) in 2018 or 2017 . As of December 31, 2018 , PSE&G had an aggregate of 7.5 million shares of $100 par value and 10 million shares of $25 par value Cumulative Preferred Stock, which were authorized and unissued and which, upon issuance, may or may not provide for mandatory sinking fund redemption.

Financial Risk Management Activ

Financial Risk Management Activities	12 Months Ended
	Dec. 31, 2018
Derivative [Line Items]
Financial Risk Management Activities	Financial Risk Management Activities Derivative accounting guidance requires that a derivative instrument be recognized as either an asset or a liability at fair value, with changes in fair value of the derivative recognized in earnings each period. Other accounting treatments are available through special election and designation provided that the derivative instrument meets specific, restrictive criteria, both at the time of designation and on an ongoing basis. These alternative permissible treatments include NPNS, cash flow hedge and fair value hedge accounting. PSEG, Power and PSE&G have applied the NPNS scope exception to certain derivative contracts for the forward sale of generation, power procurement agreements and fuel agreements. PSEG uses interest rate swaps and other derivatives, which are designated and effective as cash flow or fair value hedges. Power enters into additional contracts that are derivatives, but are not designated as either cash flow hedges or fair value hedges. These transactions are economic hedges and are recorded at fair market value. Commodity Prices Within PSEG and its affiliate companies, Power has the most exposure to commodity price risk. Power is exposed to commodity price risk primarily relating to changes in the market price of electricity, fossil fuels and other commodities. Fluctuations in market prices result from changes in supply and demand, fuel costs, market conditions, weather, state and federal regulatory policies, environmental policies, transmission availability and other factors. Power uses a variety of derivative and non-derivative instruments, such as financial options, futures, swaps, fuel purchases and forward purchases and sales of electricity, to manage the exposure to fluctuations in commodity prices and optimize the value of Power’s expected generation. Power also uses derivatives to hedge a portion of its anticipated BGSS obligations with PSE&G. For additional information see Note 14. Commitments and Contingent Liabilities . Changes in the fair market value of these derivative contracts are recorded in earnings. Interest Rates PSEG, Power and PSE&G are subject to the risk of fluctuating interest rates in the normal course of business. Exposure to this risk is managed by targeting a balanced debt maturity profile which limits refinancing in any given period or interest rate environment. In addition, they have used a mix of fixed and floating rate debt and interest rate swaps. Fair Value Hedges PSEG enters into fair value hedges to convert fixed-rate debt into variable-rate debt. The changes in fair value of the interest rate swaps are fully offset by changes in the fair value of the underlying forecasted interest payments of the debt. There were no outstanding interest rate swaps as of December 31, 2018 or 2017 . The fair value hedges reduced interest expense by $6 million for the year ended December 31, 2016 . Cash Flow Hedges PSEG uses interest rate swaps and other derivatives, which are designated and effective as cash flow hedges, to manage its exposure to the variability of cash flows, primarily related to variable-rate debt instruments. PSEG interest rate hedges totaling $500 million were executed and terminated during the second quarter of 2018 and a loss of $(1) million was recorded in Accumulated Other Comprehensive Income (Loss) (after tax) and will amortize to interest expense over the remaining life of Power’s $700 million of 3.85% Senior Notes due June 2023 . For additional information see Note 15. Debt and Credit Facilities . There were no outstanding interest rate hedges as of December 31, 2018 and December 31, 2017 . The Accumulated Other Comprehensive Income (Loss) (after tax) related to existing and terminated interest rate derivatives designated as cash flow hedges was $(1) million as of December 31, 2018 , immaterial as of December 31, 2017 and $2 million as of December 31, 2016 . The after-tax unrealized gains (losses) on these hedges expected to be reclassified to earnings during the next 12 months is immaterial. Fair Values of Derivative Instruments The following are the fair values of derivative instruments on the Consolidated Balance Sheets. The following tables also include disclosures for offsetting derivative assets and liabilities which are subject to a master netting or similar agreement. In general, the terms of the agreements provide that in the event of an early termination the counterparties have the right to offset amounts owed or owing under that and any other agreement with the same counterparty. Accordingly, and in accordance with PSEG’s accounting policy, these positions are offset on the Consolidated Balance Sheets of Power and PSEG. For additional information see Note 18. Fair Value Measurements . The following tabular disclosure does not include the offsetting of trade receivables and payables. As of December 31, 2018 Power (A) Consolidated Not Designated Balance Sheet Location Energy- Related Contracts Netting (B) Total Power Total Derivatives Millions Derivative Contracts Current Assets $ 426 $ (415 ) $ 11 $ 11 Noncurrent Assets 137 (136 ) 1 1 Total Mark-to-Market Derivative Assets $ 563 $ (551 ) $ 12 $ 12 Derivative Contracts Current Liabilities $ (521 ) $ 510 $ (11 ) $ (11 ) Noncurrent Liabilities (198 ) 194 (4 ) (4 ) Total Mark-to-Market Derivative (Liabilities) $ (719 ) $ 704 $ (15 ) $ (15 ) Total Net Mark-to-Market Derivative Assets (Liabilities) $ (156 ) $ 153 $ (3 ) $ (3 ) 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 derivative instruments are contracts subject to master netting agreements. Contracts not subject to master netting or similar agreements are immaterial and did not have any collateral posted or received as of December 31, 2018 and 2017 . PSE&G does not have any derivative contracts subject to master netting or similar agreements. (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 Consolidated Balance Sheets. As of December 31, 2018 and 2017 , Power had net cash collateral/margin payments to counterparties of $393 million and $146 million , respectively. Of these net cash collateral/margin payments, $153 million as of December 31, 2018 and $44 million as of December 31, 2017 were netted against the corresponding net derivative contract positions. Of the $153 million as of December 31, 2018 , $(2) million was netted against current assets, $(3) million was netted against noncurrent assets, $96 million was netted against current liabilities and $62 million was netted against noncurrent liabilities. 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. 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 $22 million and $30 million as of December 31, 2018 and 2017 , respectively. As of December 31, 2018 and 2017 , Power had the contractual right of offset of $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 $15 million and $17 million as of December 31, 2018 and 2017 , respectively, related to its derivatives, net of the contractual right of offset under master agreements and the application of collateral. The following shows the effect on the Consolidated Statements of Operations and on Accumulated Other Comprehensive Loss (AOCL) of derivative instruments designated as cash flow hedges for the years ended December 31, 2018 , 2017 and 2016 . Amount of Pre-Tax Gain (Loss) Recognized in AOCL on Derivatives (Effective Portion) Location of Pre-Tax Gain (Loss) Reclassified from AOCL into Income Amount of Pre-Tax Gain (Loss) Reclassified from AOCL into Income (Effective Portion) Derivatives in Cash Flow Hedging Relationships Years Ended December 31, Years Ended December 31, 2018 2017 2016 2018 2017 2016 Millions Millions PSEG Interest Rate Swaps $ (2 ) $ — $ 3 Interest Expense $ — $ 3 $ — Total PSEG $ (2 ) $ — $ 3 $ — $ 3 $ — There were no pre-tax gains (losses) recognized in income on derivatives (ineffective portion) as of December 31, 2018 , 2017 and 2016 . The following reconciles the Accumulated Other Comprehensive Income (Loss) for derivative activity included in the AOCL of PSEG on a pre-tax and after-tax basis. Accumulated Other Comprehensive Income (Loss) Pre-Tax After-Tax Millions Balance as of December 31, 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 December 31, 2018 $ (2 ) $ (1 ) The following shows the effect on the Consolidated Statements of Operations of derivative instruments not designated as hedging instruments or as NPNS for the years ended December 31, 2018 , 2017 and 2016 . Power’s derivative contracts reflected in this table include contracts to hedge the purchase and sale of electricity and natural gas, and the purchase of fuel. The table does not include contracts which 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 Years Ended December 31, 2018 2017 2016 Millions PSEG and Power Energy-Related Contracts Operating Revenues $ (182 ) $ 66 $ 218 Energy-Related Contracts Energy Costs (9 ) (11 ) 4 Total PSEG and Power $ (191 ) $ 55 $ 222 The following table summarizes the net notional volume purchases/(sales) of open derivative transactions by commodity as of December 31, 2018 and 2017 . Type Notional Total PSEG Power PSE&G Millions As of December 31, 2018 Natural Gas Dth 358 — 358 — Electricity MWh (74 ) — (74 ) — Financial Transmission Rights (FTRs) MWh 18 — 18 — 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. The following table provides information on Power’s credit risk from wholesale counterparties, net of collateral, as of December 31, 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 December 31, 2018 , 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). Rating Current Exposure Securities held as Collateral Net Exposure Number of Counterparties >10% Net Exposure of Counterparties >10% Millions Millions Investment Grade $ 264 $ 12 $ 252 1 $ 179 (A) Non-Investment Grade 1 — 1 — — Total $ 265 $ 12 $ 253 1 $ 179 (A) Represents net exposure with PSE&G. As of December 31, 2018 , collateral held from counterparties where Power had credit exposure includes $12 million in letters of credit. As of December 31, 2018 , Power had 151 active counterparties. PSE&G’s supplier master agreements are approved by the BPU and govern the terms of its electric supply procurement contracts. These agreements define a supplier’s performance assurance requirements and allow a supplier to meet its credit requirements with a certain amount of unsecured credit. The amount of unsecured credit is determined based on the supplier’s credit ratings from the major credit rating agencies and the supplier’s tangible net worth. The credit position is based on the initial market price, which is the forward price of energy on the day the procurement transaction is executed, compared to the forward price curve for energy on the valuation day. To the extent that the forward price curve for energy exceeds the initial market price, the supplier is required to post a parental guaranty or other security instrument such as a letter of credit or cash, as collateral to the extent the credit exposure is greater than the supplier’s unsecured credit limit. As of December 31, 2018 , primarily all of the posted collateral was in the form of parental guarantees. The unsecured credit used by the suppliers represents PSE&G’s net credit exposure. PSE&G’s BGS suppliers’ credit exposure is calculated each business day. As of December 31, 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.
PSE&G [Member]
Derivative [Line Items]
Financial Risk Management Activities	Financial Risk Management Activities Derivative accounting guidance requires that a derivative instrument be recognized as either an asset or a liability at fair value, with changes in fair value of the derivative recognized in earnings each period. Other accounting treatments are available through special election and designation provided that the derivative instrument meets specific, restrictive criteria, both at the time of designation and on an ongoing basis. These alternative permissible treatments include NPNS, cash flow hedge and fair value hedge accounting. PSEG, Power and PSE&G have applied the NPNS scope exception to certain derivative contracts for the forward sale of generation, power procurement agreements and fuel agreements. PSEG uses interest rate swaps and other derivatives, which are designated and effective as cash flow or fair value hedges. Power enters into additional contracts that are derivatives, but are not designated as either cash flow hedges or fair value hedges. These transactions are economic hedges and are recorded at fair market value. Commodity Prices Within PSEG and its affiliate companies, Power has the most exposure to commodity price risk. Power is exposed to commodity price risk primarily relating to changes in the market price of electricity, fossil fuels and other commodities. Fluctuations in market prices result from changes in supply and demand, fuel costs, market conditions, weather, state and federal regulatory policies, environmental policies, transmission availability and other factors. Power uses a variety of derivative and non-derivative instruments, such as financial options, futures, swaps, fuel purchases and forward purchases and sales of electricity, to manage the exposure to fluctuations in commodity prices and optimize the value of Power’s expected generation. Power also uses derivatives to hedge a portion of its anticipated BGSS obligations with PSE&G. For additional information see Note 14. Commitments and Contingent Liabilities . Changes in the fair market value of these derivative contracts are recorded in earnings. Interest Rates PSEG, Power and PSE&G are subject to the risk of fluctuating interest rates in the normal course of business. Exposure to this risk is managed by targeting a balanced debt maturity profile which limits refinancing in any given period or interest rate environment. In addition, they have used a mix of fixed and floating rate debt and interest rate swaps. Fair Value Hedges PSEG enters into fair value hedges to convert fixed-rate debt into variable-rate debt. The changes in fair value of the interest rate swaps are fully offset by changes in the fair value of the underlying forecasted interest payments of the debt. There were no outstanding interest rate swaps as of December 31, 2018 or 2017 . The fair value hedges reduced interest expense by $6 million for the year ended December 31, 2016 . Cash Flow Hedges PSEG uses interest rate swaps and other derivatives, which are designated and effective as cash flow hedges, to manage its exposure to the variability of cash flows, primarily related to variable-rate debt instruments. PSEG interest rate hedges totaling $500 million were executed and terminated during the second quarter of 2018 and a loss of $(1) million was recorded in Accumulated Other Comprehensive Income (Loss) (after tax) and will amortize to interest expense over the remaining life of Power’s $700 million of 3.85% Senior Notes due June 2023 . For additional information see Note 15. Debt and Credit Facilities . There were no outstanding interest rate hedges as of December 31, 2018 and December 31, 2017 . The Accumulated Other Comprehensive Income (Loss) (after tax) related to existing and terminated interest rate derivatives designated as cash flow hedges was $(1) million as of December 31, 2018 , immaterial as of December 31, 2017 and $2 million as of December 31, 2016 . The after-tax unrealized gains (losses) on these hedges expected to be reclassified to earnings during the next 12 months is immaterial. Fair Values of Derivative Instruments The following are the fair values of derivative instruments on the Consolidated Balance Sheets. The following tables also include disclosures for offsetting derivative assets and liabilities which are subject to a master netting or similar agreement. In general, the terms of the agreements provide that in the event of an early termination the counterparties have the right to offset amounts owed or owing under that and any other agreement with the same counterparty. Accordingly, and in accordance with PSEG’s accounting policy, these positions are offset on the Consolidated Balance Sheets of Power and PSEG. For additional information see Note 18. Fair Value Measurements . The following tabular disclosure does not include the offsetting of trade receivables and payables. As of December 31, 2018 Power (A) Consolidated Not Designated Balance Sheet Location Energy- Related Contracts Netting (B) Total Power Total Derivatives Millions Derivative Contracts Current Assets $ 426 $ (415 ) $ 11 $ 11 Noncurrent Assets 137 (136 ) 1 1 Total Mark-to-Market Derivative Assets $ 563 $ (551 ) $ 12 $ 12 Derivative Contracts Current Liabilities $ (521 ) $ 510 $ (11 ) $ (11 ) Noncurrent Liabilities (198 ) 194 (4 ) (4 ) Total Mark-to-Market Derivative (Liabilities) $ (719 ) $ 704 $ (15 ) $ (15 ) Total Net Mark-to-Market Derivative Assets (Liabilities) $ (156 ) $ 153 $ (3 ) $ (3 ) 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 derivative instruments are contracts subject to master netting agreements. Contracts not subject to master netting or similar agreements are immaterial and did not have any collateral posted or received as of December 31, 2018 and 2017 . PSE&G does not have any derivative contracts subject to master netting or similar agreements. (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 Consolidated Balance Sheets. As of December 31, 2018 and 2017 , Power had net cash collateral/margin payments to counterparties of $393 million and $146 million , respectively. Of these net cash collateral/margin payments, $153 million as of December 31, 2018 and $44 million as of December 31, 2017 were netted against the corresponding net derivative contract positions. Of the $153 million as of December 31, 2018 , $(2) million was netted against current assets, $(3) million was netted against noncurrent assets, $96 million was netted against current liabilities and $62 million was netted against noncurrent liabilities. 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. 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 $22 million and $30 million as of December 31, 2018 and 2017 , respectively. As of December 31, 2018 and 2017 , Power had the contractual right of offset of $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 $15 million and $17 million as of December 31, 2018 and 2017 , respectively, related to its derivatives, net of the contractual right of offset under master agreements and the application of collateral. The following shows the effect on the Consolidated Statements of Operations and on Accumulated Other Comprehensive Loss (AOCL) of derivative instruments designated as cash flow hedges for the years ended December 31, 2018 , 2017 and 2016 . Amount of Pre-Tax Gain (Loss) Recognized in AOCL on Derivatives (Effective Portion) Location of Pre-Tax Gain (Loss) Reclassified from AOCL into Income Amount of Pre-Tax Gain (Loss) Reclassified from AOCL into Income (Effective Portion) Derivatives in Cash Flow Hedging Relationships Years Ended December 31, Years Ended December 31, 2018 2017 2016 2018 2017 2016 Millions Millions PSEG Interest Rate Swaps $ (2 ) $ — $ 3 Interest Expense $ — $ 3 $ — Total PSEG $ (2 ) $ — $ 3 $ — $ 3 $ — There were no pre-tax gains (losses) recognized in income on derivatives (ineffective portion) as of December 31, 2018 , 2017 and 2016 . The following reconciles the Accumulated Other Comprehensive Income (Loss) for derivative activity included in the AOCL of PSEG on a pre-tax and after-tax basis. Accumulated Other Comprehensive Income (Loss) Pre-Tax After-Tax Millions Balance as of December 31, 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 December 31, 2018 $ (2 ) $ (1 ) The following shows the effect on the Consolidated Statements of Operations of derivative instruments not designated as hedging instruments or as NPNS for the years ended December 31, 2018 , 2017 and 2016 . Power’s derivative contracts reflected in this table include contracts to hedge the purchase and sale of electricity and natural gas, and the purchase of fuel. The table does not include contracts which 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 Years Ended December 31, 2018 2017 2016 Millions PSEG and Power Energy-Related Contracts Operating Revenues $ (182 ) $ 66 $ 218 Energy-Related Contracts Energy Costs (9 ) (11 ) 4 Total PSEG and Power $ (191 ) $ 55 $ 222 The following table summarizes the net notional volume purchases/(sales) of open derivative transactions by commodity as of December 31, 2018 and 2017 . Type Notional Total PSEG Power PSE&G Millions As of December 31, 2018 Natural Gas Dth 358 — 358 — Electricity MWh (74 ) — (74 ) — Financial Transmission Rights (FTRs) MWh 18 — 18 — 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. The following table provides information on Power’s credit risk from wholesale counterparties, net of collateral, as of December 31, 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 December 31, 2018 , 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). Rating Current Exposure Securities held as Collateral Net Exposure Number of Counterparties >10% Net Exposure of Counterparties >10% Millions Millions Investment Grade $ 264 $ 12 $ 252 1 $ 179 (A) Non-Investment Grade 1 — 1 — — Total $ 265 $ 12 $ 253 1 $ 179 (A) Represents net exposure with PSE&G. As of December 31, 2018 , collateral held from counterparties where Power had credit exposure includes $12 million in letters of credit. As of December 31, 2018 , Power had 151 active counterparties. PSE&G’s supplier master agreements are approved by the BPU and govern the terms of its electric supply procurement contracts. These agreements define a supplier’s performance assurance requirements and allow a supplier to meet its credit requirements with a certain amount of unsecured credit. The amount of unsecured credit is determined based on the supplier’s credit ratings from the major credit rating agencies and the supplier’s tangible net worth. The credit position is based on the initial market price, which is the forward price of energy on the day the procurement transaction is executed, compared to the forward price curve for energy on the valuation day. To the extent that the forward price curve for energy exceeds the initial market price, the supplier is required to post a parental guaranty or other security instrument such as a letter of credit or cash, as collateral to the extent the credit exposure is greater than the supplier’s unsecured credit limit. As of December 31, 2018 , primarily all of the posted collateral was in the form of parental guarantees. The unsecured credit used by the suppliers represents PSE&G’s net credit exposure. PSE&G’s BGS suppliers’ credit exposure is calculated each business day. As of December 31, 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.
Power [Member]
Derivative [Line Items]
Financial Risk Management Activities	Financial Risk Management Activities Derivative accounting guidance requires that a derivative instrument be recognized as either an asset or a liability at fair value, with changes in fair value of the derivative recognized in earnings each period. Other accounting treatments are available through special election and designation provided that the derivative instrument meets specific, restrictive criteria, both at the time of designation and on an ongoing basis. These alternative permissible treatments include NPNS, cash flow hedge and fair value hedge accounting. PSEG, Power and PSE&G have applied the NPNS scope exception to certain derivative contracts for the forward sale of generation, power procurement agreements and fuel agreements. PSEG uses interest rate swaps and other derivatives, which are designated and effective as cash flow or fair value hedges. Power enters into additional contracts that are derivatives, but are not designated as either cash flow hedges or fair value hedges. These transactions are economic hedges and are recorded at fair market value. Commodity Prices Within PSEG and its affiliate companies, Power has the most exposure to commodity price risk. Power is exposed to commodity price risk primarily relating to changes in the market price of electricity, fossil fuels and other commodities. Fluctuations in market prices result from changes in supply and demand, fuel costs, market conditions, weather, state and federal regulatory policies, environmental policies, transmission availability and other factors. Power uses a variety of derivative and non-derivative instruments, such as financial options, futures, swaps, fuel purchases and forward purchases and sales of electricity, to manage the exposure to fluctuations in commodity prices and optimize the value of Power’s expected generation. Power also uses derivatives to hedge a portion of its anticipated BGSS obligations with PSE&G. For additional information see Note 14. Commitments and Contingent Liabilities . Changes in the fair market value of these derivative contracts are recorded in earnings. Interest Rates PSEG, Power and PSE&G are subject to the risk of fluctuating interest rates in the normal course of business. Exposure to this risk is managed by targeting a balanced debt maturity profile which limits refinancing in any given period or interest rate environment. In addition, they have used a mix of fixed and floating rate debt and interest rate swaps. Fair Value Hedges PSEG enters into fair value hedges to convert fixed-rate debt into variable-rate debt. The changes in fair value of the interest rate swaps are fully offset by changes in the fair value of the underlying forecasted interest payments of the debt. There were no outstanding interest rate swaps as of December 31, 2018 or 2017 . The fair value hedges reduced interest expense by $6 million for the year ended December 31, 2016 . Cash Flow Hedges PSEG uses interest rate swaps and other derivatives, which are designated and effective as cash flow hedges, to manage its exposure to the variability of cash flows, primarily related to variable-rate debt instruments. PSEG interest rate hedges totaling $500 million were executed and terminated during the second quarter of 2018 and a loss of $(1) million was recorded in Accumulated Other Comprehensive Income (Loss) (after tax) and will amortize to interest expense over the remaining life of Power’s $700 million of 3.85% Senior Notes due June 2023 . For additional information see Note 15. Debt and Credit Facilities . There were no outstanding interest rate hedges as of December 31, 2018 and December 31, 2017 . The Accumulated Other Comprehensive Income (Loss) (after tax) related to existing and terminated interest rate derivatives designated as cash flow hedges was $(1) million as of December 31, 2018 , immaterial as of December 31, 2017 and $2 million as of December 31, 2016 . The after-tax unrealized gains (losses) on these hedges expected to be reclassified to earnings during the next 12 months is immaterial. Fair Values of Derivative Instruments The following are the fair values of derivative instruments on the Consolidated Balance Sheets. The following tables also include disclosures for offsetting derivative assets and liabilities which are subject to a master netting or similar agreement. In general, the terms of the agreements provide that in the event of an early termination the counterparties have the right to offset amounts owed or owing under that and any other agreement with the same counterparty. Accordingly, and in accordance with PSEG’s accounting policy, these positions are offset on the Consolidated Balance Sheets of Power and PSEG. For additional information see Note 18. Fair Value Measurements . The following tabular disclosure does not include the offsetting of trade receivables and payables. As of December 31, 2018 Power (A) Consolidated Not Designated Balance Sheet Location Energy- Related Contracts Netting (B) Total Power Total Derivatives Millions Derivative Contracts Current Assets $ 426 $ (415 ) $ 11 $ 11 Noncurrent Assets 137 (136 ) 1 1 Total Mark-to-Market Derivative Assets $ 563 $ (551 ) $ 12 $ 12 Derivative Contracts Current Liabilities $ (521 ) $ 510 $ (11 ) $ (11 ) Noncurrent Liabilities (198 ) 194 (4 ) (4 ) Total Mark-to-Market Derivative (Liabilities) $ (719 ) $ 704 $ (15 ) $ (15 ) Total Net Mark-to-Market Derivative Assets (Liabilities) $ (156 ) $ 153 $ (3 ) $ (3 ) 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 derivative instruments are contracts subject to master netting agreements. Contracts not subject to master netting or similar agreements are immaterial and did not have any collateral posted or received as of December 31, 2018 and 2017 . PSE&G does not have any derivative contracts subject to master netting or similar agreements. (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 Consolidated Balance Sheets. As of December 31, 2018 and 2017 , Power had net cash collateral/margin payments to counterparties of $393 million and $146 million , respectively. Of these net cash collateral/margin payments, $153 million as of December 31, 2018 and $44 million as of December 31, 2017 were netted against the corresponding net derivative contract positions. Of the $153 million as of December 31, 2018 , $(2) million was netted against current assets, $(3) million was netted against noncurrent assets, $96 million was netted against current liabilities and $62 million was netted against noncurrent liabilities. 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. 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 $22 million and $30 million as of December 31, 2018 and 2017 , respectively. As of December 31, 2018 and 2017 , Power had the contractual right of offset of $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 $15 million and $17 million as of December 31, 2018 and 2017 , respectively, related to its derivatives, net of the contractual right of offset under master agreements and the application of collateral. The following shows the effect on the Consolidated Statements of Operations and on Accumulated Other Comprehensive Loss (AOCL) of derivative instruments designated as cash flow hedges for the years ended December 31, 2018 , 2017 and 2016 . Amount of Pre-Tax Gain (Loss) Recognized in AOCL on Derivatives (Effective Portion) Location of Pre-Tax Gain (Loss) Reclassified from AOCL into Income Amount of Pre-Tax Gain (Loss) Reclassified from AOCL into Income (Effective Portion) Derivatives in Cash Flow Hedging Relationships Years Ended December 31, Years Ended December 31, 2018 2017 2016 2018 2017 2016 Millions Millions PSEG Interest Rate Swaps $ (2 ) $ — $ 3 Interest Expense $ — $ 3 $ — Total PSEG $ (2 ) $ — $ 3 $ — $ 3 $ — There were no pre-tax gains (losses) recognized in income on derivatives (ineffective portion) as of December 31, 2018 , 2017 and 2016 . The following reconciles the Accumulated Other Comprehensive Income (Loss) for derivative activity included in the AOCL of PSEG on a pre-tax and after-tax basis. Accumulated Other Comprehensive Income (Loss) Pre-Tax After-Tax Millions Balance as of December 31, 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 December 31, 2018 $ (2 ) $ (1 ) The following shows the effect on the Consolidated Statements of Operations of derivative instruments not designated as hedging instruments or as NPNS for the years ended December 31, 2018 , 2017 and 2016 . Power’s derivative contracts reflected in this table include contracts to hedge the purchase and sale of electricity and natural gas, and the purchase of fuel. The table does not include contracts which 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 Years Ended December 31, 2018 2017 2016 Millions PSEG and Power Energy-Related Contracts Operating Revenues $ (182 ) $ 66 $ 218 Energy-Related Contracts Energy Costs (9 ) (11 ) 4 Total PSEG and Power $ (191 ) $ 55 $ 222 The following table summarizes the net notional volume purchases/(sales) of open derivative transactions by commodity as of December 31, 2018 and 2017 . Type Notional Total PSEG Power PSE&G Millions As of December 31, 2018 Natural Gas Dth 358 — 358 — Electricity MWh (74 ) — (74 ) — Financial Transmission Rights (FTRs) MWh 18 — 18 — 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. The following table provides information on Power’s credit risk from wholesale counterparties, net of collateral, as of December 31, 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 December 31, 2018 , 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). Rating Current Exposure Securities held as Collateral Net Exposure Number of Counterparties >10% Net Exposure of Counterparties >10% Millions Millions Investment Grade $ 264 $ 12 $ 252 1 $ 179 (A) Non-Investment Grade 1 — 1 — — Total $ 265 $ 12 $ 253 1 $ 179 (A) Represents net exposure with PSE&G. As of December 31, 2018 , collateral held from counterparties where Power had credit exposure includes $12 million in letters of credit. As of December 31, 2018 , Power had 151 active counterparties. PSE&G’s supplier master agreements are approved by the BPU and govern the terms of its electric supply procurement contracts. These agreements define a supplier’s performance assurance requirements and allow a supplier to meet its credit requirements with a certain amount of unsecured credit. The amount of unsecured credit is determined based on the supplier’s credit ratings from the major credit rating agencies and the supplier’s tangible net worth. The credit position is based on the initial market price, which is the forward price of energy on the day the procurement transaction is executed, compared to the forward price curve for energy on the valuation day. To the extent that the forward price curve for energy exceeds the initial market price, the supplier is required to post a parental guaranty or other security instrument such as a letter of credit or cash, as collateral to the extent the credit exposure is greater than the supplier’s unsecured credit limit. As of December 31, 2018 , primarily all of the posted collateral was in the form of parental guarantees. The unsecured credit used by the suppliers represents PSE&G’s net credit exposure. PSE&G’s BGS suppliers’ credit exposure is calculated each business day. As of December 31, 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.

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2018
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Fair Value Measurements	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 December 31, 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 December 31, 2018 and December 31, 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. Recurring Fair Value Measurements as of December 31, 2018 Description Total Netting (D) Quoted Market Prices for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Millions PSEG Assets: Cash Equivalents (A) $ 100 $ — $ 100 $ — $ — Derivative Contracts: Energy-Related Contracts (B) $ 12 $ (551 ) $ 29 $ 527 $ 7 NDT Fund (C) Equity Securities $ 900 $ — $ 898 $ 2 $ — Debt Securities—U.S. Treasury $ 171 $ — $ — $ 171 $ — Debt Securities—Govt Other $ 320 $ — $ — $ 320 $ — Debt Securities—Corporate $ 487 $ — $ — $ 487 $ — Rabbi Trust (C) Equity Securities $ 23 $ — $ 23 $ — $ — Debt Securities—U.S. Treasury $ 69 $ — $ — $ 69 $ — Debt Securities—Govt Other $ 40 $ — $ — $ 40 $ — Debt Securities—Corporate $ 92 $ — $ — $ 92 $ — Liabilities: Derivative Contracts: Energy-Related Contracts (B) $ (15 ) $ 704 $ (36 ) $ (677 ) $ (6 ) PSE&G Assets: Rabbi Trust (C) Equity Securities $ 5 $ — $ 5 $ — $ — Debt Securities—U.S. Treasury $ 14 $ — $ — $ 14 $ — Debt Securities—Govt Other $ 8 $ — $ — $ 8 $ — Debt Securities—Corporate $ 18 $ — $ — $ 18 $ — Power Assets: Derivative Contracts: Energy-Related Contracts (B) $ 12 $ (551 ) $ 29 $ 527 $ 7 NDT Fund (C) Equity Securities $ 900 $ — $ 898 $ 2 $ — Debt Securities—U.S. Treasury $ 171 $ — $ — $ 171 $ — Debt Securities—Govt Other $ 320 $ — $ — $ 320 $ — Debt Securities—Corporate $ 487 $ — $ — $ 487 $ — Rabbi Trust (C) Equity Securities $ 6 $ — $ 6 $ — $ — Debt Securities—U.S. Treasury $ 17 $ — $ — $ 17 $ — Debt Securities—Govt Other $ 10 $ — $ — $ 10 $ — Debt Securities—Corporate $ 23 $ — $ — $ 23 $ — Liabilities: Derivative Contracts: Energy-Related Contracts (B) $ (15 ) $ 704 $ (36 ) $ (677 ) $ (6 ) Recurring Fair Value Measurements as of December 31, 2017 Description Total Netting (D) Quoted Market Prices for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Millions PSEG Assets: Cash Equivalents (A) $ 223 $ — $ 223 $ — $ — Derivative Contracts: Energy-Related Contracts (B) $ 36 $ (433 ) $ 15 $ 442 $ 12 NDT Fund (C) 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 (C) 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 (B) $ (21 ) $ 477 $ (8 ) $ (485 ) $ (5 ) PSE&G Assets: Cash Equivalents (A) $ 223 $ — $ 223 $ — $ — Rabbi Trust (C) 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 (B) $ 36 $ (433 ) $ 15 $ 442 $ 12 NDT Fund (C) 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 (C) 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 (B) $ (21 ) $ 477 $ (8 ) $ (485 ) $ (5 ) (A) Represents money market mutual funds. (B) 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 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) The NDT Fund maintains investments in various equity and fixed income securities. The Rabbi Trust maintains investments in a Russell 3000 index fund and various fixed income securities. These securities are generally valued with prices that are either exchange provided (equity securities) or market transactions for comparable securities and/or broker quotes (fixed income securities). Level 1—Investments in marketable equity securities within the NDT Fund are primarily investments in common stocks across a broad range of industries and sectors. Most equity securities are priced utilizing the principal market close price or, in some cases, midpoint, bid or ask price. Certain other equity securities in the NDT and Rabbi Trust Funds consist primarily of investments in Dreyfus money market funds which seek a high level of current income as is consistent with the preservation of capital and the maintenance of liquidity. To pursue its goals, the funds normally invest in diversified portfolios of high quality, short-term, dollar-denominated debt securities and government securities. The funds’ NAV 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 investment grade corporate bonds, collateralized mortgage obligations, asset-backed securities and certain government and U.S. Treasury obligations or Federal Agency asset-backed securities and municipal bonds with a wide range of maturities. Since many fixed income securities do not trade on a daily basis, they are priced using an evaluated pricing methodology that varies by asset class and reflects observable market information such as the most recent exchange price or quoted bid for similar securities. Market-based standard inputs typically include benchmark yields, reported trades, broker/dealer quotes and issuer spreads. The preferred stocks are not actively traded on a daily basis and therefore, are also priced using an evaluated pricing methodology. Certain short-term investments are valued using observable market prices or market parameters such as time-to-maturity, coupon rate, quality rating and current yield. (D) Represents the netting of fair value balances with the same counterparty (where the right of offset exists) and the application of collateral. See Note 17. Financial Risk Management Activities for additional detail. Additional Information Regarding Level 3 Measurements For valuations that include both observable and unobservable inputs, if the unobservable input is determined to be significant to the overall inputs, the entire valuation is categorized in Level 3. This includes derivatives valued using indicative price quotations for contracts with tenors that extend into periods with no observable pricing. In instances where observable data is unavailable, consideration is given to the assumptions that market participants would use in valuing the asset or liability. This includes assumptions about market risks such as liquidity, volatility and contract duration. Such instruments are categorized in Level 3 because the model inputs generally are not observable. PSEG’s Risk Management Committee (RMC) approves risk management policies and objectives for risk assessment, control and valuation, counterparty credit approval and the monitoring and reporting of risk exposures. The RMC reports to the Corporate Governance and Audit Committees of the PSEG Board on the scope of the risk management activities and is responsible for approving all valuation procedures at PSEG. Forward price curves for the power market utilized by 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. 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 physical gas contracts have an unobservable component in their respective forward price curves, the fluctuations in fair value have been driven primarily by changes in the observable inputs. The following tables provide details surrounding significant Level 3 valuations as of December 31, 2018 and 2017 . Quantitative Information About Level 3 Fair Value Measurements Commodity Level 3 Position Fair Value as of December 31, 2018 Valuation Technique(s) Significant Unobservable Input Range Assets (Liabilities) Millions Power Electricity Electric Load Contracts $ 2 $ (5 ) Discounted Cash flow Historic Load Variability 0% to 15% Gas Gas Physical Contracts 5 (1 ) Discounted Cash flow Average Historical Basis -40% to 0% Total Power $ 7 $ (6 ) Total PSEG $ 7 $ (6 ) Quantitative Information About Level 3 Fair Value Measurements Commodity Level 3 Position Fair Value as of December 31, 2017 Valuation Technique(s) Significant Unobservable 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 ) 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. A reconciliation of the beginning and ending balances of Level 3 derivative contracts and securities for the years ended December 31, 2018 and 2017 , respectively, follows: Changes in Level 3 Assets and (Liabilities) Measured at Fair Value on a Recurring Basis for the Year Ended December 31, 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 Balance as of December 31, 2018 Millions PSEG Net Derivative Assets (Liabilities) $ 7 $ (6 ) $ — $ — $ — $ — $ 1 Power Net Derivative Assets (Liabilities) $ 7 $ (6 ) $ — $ — $ — $ — $ 1 Changes in Level 3 Assets and (Liabilities) Measured at Fair Value on a Recurring Basis for the Year Ended December 31, 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 December 31, 2017 Millions PSEG Net Derivative Assets (Liabilities) $ 1 $ 26 $ 5 $ — $ (24 ) $ (1 ) $ 7 PSE&G Net Derivative Assets (Liabilities) $ (5 ) $ — $ 5 $ — $ — $ — $ — Power Net Derivative Assets (Liabilities) $ 6 $ 26 $ — $ — $ (24 ) $ (1 ) $ 7 (A) Unrealized gains (losses) in the following table represent the change in derivative assets and liabilities still held as of December 31, 2018 and 2017. Years Ended December 31, 2018 2017 Total Gains (Losses) Unrealized Gains (Losses) Total Gains (Losses) Unrealized Gains (Losses) Millions PSEG and Power Operating Revenues $ (2 ) $ — $ 14 $ (9 ) Energy Costs (4 ) (6 ) 12 12 Total $ (6 ) $ (6 ) $ 26 $ 3 (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. (C) Represents $(24) million in settlements for derivative contracts in 2017 . (D) During the year ended December 31, 2017 , $(1) million of net derivatives assets/liabilities were transferred from Level 2 to Level 3. There were no transfers in 2018. As of December 31, 2018 , PSEG carried $2.2 billion of net assets that are measured at fair value on a recurring basis, of which $1 million of net assets were measured using unobservable inputs and classified as Level 3 within the fair value hierarchy. As of December 31, 2017 , PSEG carried $2.6 billion of net assets that are measured at fair value on a recurring basis, of which $7 million of net assets were measured using unobservable inputs and classified as Level 3 within the fair value hierarchy.
PSE&G [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Fair Value Measurements	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 December 31, 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 December 31, 2018 and December 31, 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. Recurring Fair Value Measurements as of December 31, 2018 Description Total Netting (D) Quoted Market Prices for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Millions PSEG Assets: Cash Equivalents (A) $ 100 $ — $ 100 $ — $ — Derivative Contracts: Energy-Related Contracts (B) $ 12 $ (551 ) $ 29 $ 527 $ 7 NDT Fund (C) Equity Securities $ 900 $ — $ 898 $ 2 $ — Debt Securities—U.S. Treasury $ 171 $ — $ — $ 171 $ — Debt Securities—Govt Other $ 320 $ — $ — $ 320 $ — Debt Securities—Corporate $ 487 $ — $ — $ 487 $ — Rabbi Trust (C) Equity Securities $ 23 $ — $ 23 $ — $ — Debt Securities—U.S. Treasury $ 69 $ — $ — $ 69 $ — Debt Securities—Govt Other $ 40 $ — $ — $ 40 $ — Debt Securities—Corporate $ 92 $ — $ — $ 92 $ — Liabilities: Derivative Contracts: Energy-Related Contracts (B) $ (15 ) $ 704 $ (36 ) $ (677 ) $ (6 ) PSE&G Assets: Rabbi Trust (C) Equity Securities $ 5 $ — $ 5 $ — $ — Debt Securities—U.S. Treasury $ 14 $ — $ — $ 14 $ — Debt Securities—Govt Other $ 8 $ — $ — $ 8 $ — Debt Securities—Corporate $ 18 $ — $ — $ 18 $ — Power Assets: Derivative Contracts: Energy-Related Contracts (B) $ 12 $ (551 ) $ 29 $ 527 $ 7 NDT Fund (C) Equity Securities $ 900 $ — $ 898 $ 2 $ — Debt Securities—U.S. Treasury $ 171 $ — $ — $ 171 $ — Debt Securities—Govt Other $ 320 $ — $ — $ 320 $ — Debt Securities—Corporate $ 487 $ — $ — $ 487 $ — Rabbi Trust (C) Equity Securities $ 6 $ — $ 6 $ — $ — Debt Securities—U.S. Treasury $ 17 $ — $ — $ 17 $ — Debt Securities—Govt Other $ 10 $ — $ — $ 10 $ — Debt Securities—Corporate $ 23 $ — $ — $ 23 $ — Liabilities: Derivative Contracts: Energy-Related Contracts (B) $ (15 ) $ 704 $ (36 ) $ (677 ) $ (6 ) Recurring Fair Value Measurements as of December 31, 2017 Description Total Netting (D) Quoted Market Prices for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Millions PSEG Assets: Cash Equivalents (A) $ 223 $ — $ 223 $ — $ — Derivative Contracts: Energy-Related Contracts (B) $ 36 $ (433 ) $ 15 $ 442 $ 12 NDT Fund (C) 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 (C) 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 (B) $ (21 ) $ 477 $ (8 ) $ (485 ) $ (5 ) PSE&G Assets: Cash Equivalents (A) $ 223 $ — $ 223 $ — $ — Rabbi Trust (C) 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 (B) $ 36 $ (433 ) $ 15 $ 442 $ 12 NDT Fund (C) 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 (C) 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 (B) $ (21 ) $ 477 $ (8 ) $ (485 ) $ (5 ) (A) Represents money market mutual funds. (B) 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 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) The NDT Fund maintains investments in various equity and fixed income securities. The Rabbi Trust maintains investments in a Russell 3000 index fund and various fixed income securities. These securities are generally valued with prices that are either exchange provided (equity securities) or market transactions for comparable securities and/or broker quotes (fixed income securities). Level 1—Investments in marketable equity securities within the NDT Fund are primarily investments in common stocks across a broad range of industries and sectors. Most equity securities are priced utilizing the principal market close price or, in some cases, midpoint, bid or ask price. Certain other equity securities in the NDT and Rabbi Trust Funds consist primarily of investments in Dreyfus money market funds which seek a high level of current income as is consistent with the preservation of capital and the maintenance of liquidity. To pursue its goals, the funds normally invest in diversified portfolios of high quality, short-term, dollar-denominated debt securities and government securities. The funds’ NAV 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 investment grade corporate bonds, collateralized mortgage obligations, asset-backed securities and certain government and U.S. Treasury obligations or Federal Agency asset-backed securities and municipal bonds with a wide range of maturities. Since many fixed income securities do not trade on a daily basis, they are priced using an evaluated pricing methodology that varies by asset class and reflects observable market information such as the most recent exchange price or quoted bid for similar securities. Market-based standard inputs typically include benchmark yields, reported trades, broker/dealer quotes and issuer spreads. The preferred stocks are not actively traded on a daily basis and therefore, are also priced using an evaluated pricing methodology. Certain short-term investments are valued using observable market prices or market parameters such as time-to-maturity, coupon rate, quality rating and current yield. (D) Represents the netting of fair value balances with the same counterparty (where the right of offset exists) and the application of collateral. See Note 17. Financial Risk Management Activities for additional detail. Additional Information Regarding Level 3 Measurements For valuations that include both observable and unobservable inputs, if the unobservable input is determined to be significant to the overall inputs, the entire valuation is categorized in Level 3. This includes derivatives valued using indicative price quotations for contracts with tenors that extend into periods with no observable pricing. In instances where observable data is unavailable, consideration is given to the assumptions that market participants would use in valuing the asset or liability. This includes assumptions about market risks such as liquidity, volatility and contract duration. Such instruments are categorized in Level 3 because the model inputs generally are not observable. PSEG’s Risk Management Committee (RMC) approves risk management policies and objectives for risk assessment, control and valuation, counterparty credit approval and the monitoring and reporting of risk exposures. The RMC reports to the Corporate Governance and Audit Committees of the PSEG Board on the scope of the risk management activities and is responsible for approving all valuation procedures at PSEG. Forward price curves for the power market utilized by 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. 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 physical gas contracts have an unobservable component in their respective forward price curves, the fluctuations in fair value have been driven primarily by changes in the observable inputs. The following tables provide details surrounding significant Level 3 valuations as of December 31, 2018 and 2017 . Quantitative Information About Level 3 Fair Value Measurements Commodity Level 3 Position Fair Value as of December 31, 2018 Valuation Technique(s) Significant Unobservable Input Range Assets (Liabilities) Millions Power Electricity Electric Load Contracts $ 2 $ (5 ) Discounted Cash flow Historic Load Variability 0% to 15% Gas Gas Physical Contracts 5 (1 ) Discounted Cash flow Average Historical Basis -40% to 0% Total Power $ 7 $ (6 ) Total PSEG $ 7 $ (6 ) Quantitative Information About Level 3 Fair Value Measurements Commodity Level 3 Position Fair Value as of December 31, 2017 Valuation Technique(s) Significant Unobservable 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 ) 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. A reconciliation of the beginning and ending balances of Level 3 derivative contracts and securities for the years ended December 31, 2018 and 2017 , respectively, follows: Changes in Level 3 Assets and (Liabilities) Measured at Fair Value on a Recurring Basis for the Year Ended December 31, 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 Balance as of December 31, 2018 Millions PSEG Net Derivative Assets (Liabilities) $ 7 $ (6 ) $ — $ — $ — $ — $ 1 Power Net Derivative Assets (Liabilities) $ 7 $ (6 ) $ — $ — $ — $ — $ 1 Changes in Level 3 Assets and (Liabilities) Measured at Fair Value on a Recurring Basis for the Year Ended December 31, 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 December 31, 2017 Millions PSEG Net Derivative Assets (Liabilities) $ 1 $ 26 $ 5 $ — $ (24 ) $ (1 ) $ 7 PSE&G Net Derivative Assets (Liabilities) $ (5 ) $ — $ 5 $ — $ — $ — $ — Power Net Derivative Assets (Liabilities) $ 6 $ 26 $ — $ — $ (24 ) $ (1 ) $ 7 (A) Unrealized gains (losses) in the following table represent the change in derivative assets and liabilities still held as of December 31, 2018 and 2017. Years Ended December 31, 2018 2017 Total Gains (Losses) Unrealized Gains (Losses) Total Gains (Losses) Unrealized Gains (Losses) Millions PSEG and Power Operating Revenues $ (2 ) $ — $ 14 $ (9 ) Energy Costs (4 ) (6 ) 12 12 Total $ (6 ) $ (6 ) $ 26 $ 3 (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. (C) Represents $(24) million in settlements for derivative contracts in 2017 . (D) During the year ended December 31, 2017 , $(1) million of net derivatives assets/liabilities were transferred from Level 2 to Level 3. There were no transfers in 2018. As of December 31, 2018 , PSEG carried $2.2 billion of net assets that are measured at fair value on a recurring basis, of which $1 million of net assets were measured using unobservable inputs and classified as Level 3 within the fair value hierarchy. As of December 31, 2017 , PSEG carried $2.6 billion of net assets that are measured at fair value on a recurring basis, of which $7 million of net assets were measured using unobservable inputs and classified as Level 3 within the fair value hierarchy.
Power [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Fair Value Measurements	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 December 31, 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 December 31, 2018 and December 31, 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. Recurring Fair Value Measurements as of December 31, 2018 Description Total Netting (D) Quoted Market Prices for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Millions PSEG Assets: Cash Equivalents (A) $ 100 $ — $ 100 $ — $ — Derivative Contracts: Energy-Related Contracts (B) $ 12 $ (551 ) $ 29 $ 527 $ 7 NDT Fund (C) Equity Securities $ 900 $ — $ 898 $ 2 $ — Debt Securities—U.S. Treasury $ 171 $ — $ — $ 171 $ — Debt Securities—Govt Other $ 320 $ — $ — $ 320 $ — Debt Securities—Corporate $ 487 $ — $ — $ 487 $ — Rabbi Trust (C) Equity Securities $ 23 $ — $ 23 $ — $ — Debt Securities—U.S. Treasury $ 69 $ — $ — $ 69 $ — Debt Securities—Govt Other $ 40 $ — $ — $ 40 $ — Debt Securities—Corporate $ 92 $ — $ — $ 92 $ — Liabilities: Derivative Contracts: Energy-Related Contracts (B) $ (15 ) $ 704 $ (36 ) $ (677 ) $ (6 ) PSE&G Assets: Rabbi Trust (C) Equity Securities $ 5 $ — $ 5 $ — $ — Debt Securities—U.S. Treasury $ 14 $ — $ — $ 14 $ — Debt Securities—Govt Other $ 8 $ — $ — $ 8 $ — Debt Securities—Corporate $ 18 $ — $ — $ 18 $ — Power Assets: Derivative Contracts: Energy-Related Contracts (B) $ 12 $ (551 ) $ 29 $ 527 $ 7 NDT Fund (C) Equity Securities $ 900 $ — $ 898 $ 2 $ — Debt Securities—U.S. Treasury $ 171 $ — $ — $ 171 $ — Debt Securities—Govt Other $ 320 $ — $ — $ 320 $ — Debt Securities—Corporate $ 487 $ — $ — $ 487 $ — Rabbi Trust (C) Equity Securities $ 6 $ — $ 6 $ — $ — Debt Securities—U.S. Treasury $ 17 $ — $ — $ 17 $ — Debt Securities—Govt Other $ 10 $ — $ — $ 10 $ — Debt Securities—Corporate $ 23 $ — $ — $ 23 $ — Liabilities: Derivative Contracts: Energy-Related Contracts (B) $ (15 ) $ 704 $ (36 ) $ (677 ) $ (6 ) Recurring Fair Value Measurements as of December 31, 2017 Description Total Netting (D) Quoted Market Prices for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Millions PSEG Assets: Cash Equivalents (A) $ 223 $ — $ 223 $ — $ — Derivative Contracts: Energy-Related Contracts (B) $ 36 $ (433 ) $ 15 $ 442 $ 12 NDT Fund (C) 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 (C) 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 (B) $ (21 ) $ 477 $ (8 ) $ (485 ) $ (5 ) PSE&G Assets: Cash Equivalents (A) $ 223 $ — $ 223 $ — $ — Rabbi Trust (C) 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 (B) $ 36 $ (433 ) $ 15 $ 442 $ 12 NDT Fund (C) 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 (C) 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 (B) $ (21 ) $ 477 $ (8 ) $ (485 ) $ (5 ) (A) Represents money market mutual funds. (B) 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 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) The NDT Fund maintains investments in various equity and fixed income securities. The Rabbi Trust maintains investments in a Russell 3000 index fund and various fixed income securities. These securities are generally valued with prices that are either exchange provided (equity securities) or market transactions for comparable securities and/or broker quotes (fixed income securities). Level 1—Investments in marketable equity securities within the NDT Fund are primarily investments in common stocks across a broad range of industries and sectors. Most equity securities are priced utilizing the principal market close price or, in some cases, midpoint, bid or ask price. Certain other equity securities in the NDT and Rabbi Trust Funds consist primarily of investments in Dreyfus money market funds which seek a high level of current income as is consistent with the preservation of capital and the maintenance of liquidity. To pursue its goals, the funds normally invest in diversified portfolios of high quality, short-term, dollar-denominated debt securities and government securities. The funds’ NAV 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 investment grade corporate bonds, collateralized mortgage obligations, asset-backed securities and certain government and U.S. Treasury obligations or Federal Agency asset-backed securities and municipal bonds with a wide range of maturities. Since many fixed income securities do not trade on a daily basis, they are priced using an evaluated pricing methodology that varies by asset class and reflects observable market information such as the most recent exchange price or quoted bid for similar securities. Market-based standard inputs typically include benchmark yields, reported trades, broker/dealer quotes and issuer spreads. The preferred stocks are not actively traded on a daily basis and therefore, are also priced using an evaluated pricing methodology. Certain short-term investments are valued using observable market prices or market parameters such as time-to-maturity, coupon rate, quality rating and current yield. (D) Represents the netting of fair value balances with the same counterparty (where the right of offset exists) and the application of collateral. See Note 17. Financial Risk Management Activities for additional detail. Additional Information Regarding Level 3 Measurements For valuations that include both observable and unobservable inputs, if the unobservable input is determined to be significant to the overall inputs, the entire valuation is categorized in Level 3. This includes derivatives valued using indicative price quotations for contracts with tenors that extend into periods with no observable pricing. In instances where observable data is unavailable, consideration is given to the assumptions that market participants would use in valuing the asset or liability. This includes assumptions about market risks such as liquidity, volatility and contract duration. Such instruments are categorized in Level 3 because the model inputs generally are not observable. PSEG’s Risk Management Committee (RMC) approves risk management policies and objectives for risk assessment, control and valuation, counterparty credit approval and the monitoring and reporting of risk exposures. The RMC reports to the Corporate Governance and Audit Committees of the PSEG Board on the scope of the risk management activities and is responsible for approving all valuation procedures at PSEG. Forward price curves for the power market utilized by 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. 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 physical gas contracts have an unobservable component in their respective forward price curves, the fluctuations in fair value have been driven primarily by changes in the observable inputs. The following tables provide details surrounding significant Level 3 valuations as of December 31, 2018 and 2017 . Quantitative Information About Level 3 Fair Value Measurements Commodity Level 3 Position Fair Value as of December 31, 2018 Valuation Technique(s) Significant Unobservable Input Range Assets (Liabilities) Millions Power Electricity Electric Load Contracts $ 2 $ (5 ) Discounted Cash flow Historic Load Variability 0% to 15% Gas Gas Physical Contracts 5 (1 ) Discounted Cash flow Average Historical Basis -40% to 0% Total Power $ 7 $ (6 ) Total PSEG $ 7 $ (6 ) Quantitative Information About Level 3 Fair Value Measurements Commodity Level 3 Position Fair Value as of December 31, 2017 Valuation Technique(s) Significant Unobservable 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 ) 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. A reconciliation of the beginning and ending balances of Level 3 derivative contracts and securities for the years ended December 31, 2018 and 2017 , respectively, follows: Changes in Level 3 Assets and (Liabilities) Measured at Fair Value on a Recurring Basis for the Year Ended December 31, 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 Balance as of December 31, 2018 Millions PSEG Net Derivative Assets (Liabilities) $ 7 $ (6 ) $ — $ — $ — $ — $ 1 Power Net Derivative Assets (Liabilities) $ 7 $ (6 ) $ — $ — $ — $ — $ 1 Changes in Level 3 Assets and (Liabilities) Measured at Fair Value on a Recurring Basis for the Year Ended December 31, 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 December 31, 2017 Millions PSEG Net Derivative Assets (Liabilities) $ 1 $ 26 $ 5 $ — $ (24 ) $ (1 ) $ 7 PSE&G Net Derivative Assets (Liabilities) $ (5 ) $ — $ 5 $ — $ — $ — $ — Power Net Derivative Assets (Liabilities) $ 6 $ 26 $ — $ — $ (24 ) $ (1 ) $ 7 (A) Unrealized gains (losses) in the following table represent the change in derivative assets and liabilities still held as of December 31, 2018 and 2017. Years Ended December 31, 2018 2017 Total Gains (Losses) Unrealized Gains (Losses) Total Gains (Losses) Unrealized Gains (Losses) Millions PSEG and Power Operating Revenues $ (2 ) $ — $ 14 $ (9 ) Energy Costs (4 ) (6 ) 12 12 Total $ (6 ) $ (6 ) $ 26 $ 3 (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. (C) Represents $(24) million in settlements for derivative contracts in 2017 . (D) During the year ended December 31, 2017 , $(1) million of net derivatives assets/liabilities were transferred from Level 2 to Level 3. There were no transfers in 2018. As of December 31, 2018 , PSEG carried $2.2 billion of net assets that are measured at fair value on a recurring basis, of which $1 million of net assets were measured using unobservable inputs and classified as Level 3 within the fair value hierarchy. As of December 31, 2017 , PSEG carried $2.6 billion of net assets that are measured at fair value on a recurring basis, of which $7 million of net assets were measured using unobservable inputs and classified as Level 3 within the fair value hierarchy.

Stock Based Compensation

Stock Based Compensation	12 Months Ended
	Dec. 31, 2018
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock Based Compensation	Stock Based Compensation PSEG’s Amended and Restated 2004 Long-Term Incentive Plan (LTIP) is a broad-based equity compensation program that provides for grants of various long-term incentive compensation awards, such as stock options, stock appreciation rights, performance share units, restricted stock, restricted stock units, cash awards or any combination thereof. The types of long-term incentive awards that have been granted and remain outstanding under the LTIP are non-qualified options to purchase shares of PSEG’s common stock, restricted stock unit awards and performance share unit awards. The type of equity award that is granted and the details of that award may vary from time to time and is subject to the approval of the Organization and Compensation Committee of PSEG’s Board of Directors (O&CC), the LTIP’s administrative committee. The LTIP currently provides for the issuance of equity awards with respect to approximately 16 million shares of common stock. As of December 31, 2018 , there were approximately 13 million shares available for future awards under the LTIP. Stock Options Under the LTIP, non-qualified options to acquire shares of PSEG common stock may be granted to officers and other key employees selected by the O&CC. Option awards are granted with an exercise price equal to the market price of PSEG’s common stock at the grant date. The options generally vest over four years of continuous service. Vesting schedules may be accelerated upon the occurrence of certain events, such as a change-in-control (unless substituted with an equity award of equal value), retirement, death or disability. Options are exercisable over a period of time designated by the O&CC (but not prior to one year or longer than ten years from the date of grant) and are subject to such other terms and conditions as the O&CC determines. Payment by option holders upon exercise of an option may be made in cash or, with the consent of the O&CC, by delivering previously acquired shares of PSEG common stock. No options have been granted since 2009. Restricted Stock Units Under the LTIP, PSEG has granted restricted stock unit awards to officers and other key employees. These awards, which are bookkeeping entries only, are subject to risk of forfeiture until vested by continued employment. Until distributed, the units are credited with dividend equivalents proportionate to the dividends paid on PSEG common stock. Distributions are made in shares of common stock. The restricted stock unit grants for 2018 and 2017 generally vest at the end of three years. Vesting may be accelerated (pro-rated basis or full vesting) upon certain events such as change-in-control, retirement, disability or death. Performance Share Units Under the LTIP, PSEG has granted performance share units to officers and other key employees. These provide for distribution in shares of PSEG common stock based on achievement of certain financial goals over a three -year performance period. Following the end of the performance period, the payout varies from 0% to 200% of the number of performance units granted depending on PSEG’s performance with respect to certain financial targets, including targets related to comparative performance against other companies in a peer group of energy companies. The performance share units are credited with dividend equivalents proportionate to the dividends paid on PSEG common stock. Distributions are made in shares of common stock. Vesting may be accelerated on a pro-rated basis for the period of the employee’s service during the performance period as a result of certain events, such as change-in-control, retirement, death or disability. Stock-Based Compensation PSEG recognizes compensation expense for stock options based on their grant date fair values, which are determined using the Black-Scholes option-pricing model. Stock option awards are expensed on a tranche-specific basis over the requisite service period of the award. Ultimately, compensation expense for stock options is recognized for awards that vest. PSEG recognizes compensation expense for restricted stock units over the vesting period based on the grant date fair value of the shares, which is equal to the market price of PSEG’s common stock on the date of the grant. PSEG recognizes compensation expense for the total shareholder return target for its performance share unit awards based on the grant date fair values of the award, which are determined using the Monte Carlo model. The accrual of compensation cost is based on the probable achievement of the performance conditions, which result in a payout from 0% to 200% of the initial grant. PSEG recognizes compensation expense for the return on invested capital target for its performance share units based on the grant date fair value of the awards, which is equal to the market price of PSEG’s common stock on the date of the grant. The accrual during the year of grant is estimated at 100% of the original grant. Such accrual may be adjusted to reflect the actual outcome. 2018 2017 2016 Millions Compensation Cost included in Operation and Maintenance Expense $ 30 $ 31 $ 29 Income Tax Benefit Recognized in Consolidated Statement of Operations $ 9 $ 13 $ 12 For 2018 , 2017 and 2016 the excess tax benefit of $3 million , $4 million and $4 million , respectively was included as financing cash flows on the Consolidated Statements of Cash Flow. PSEG recognizes compensation cost of awards issued over the shorter of the original vesting period or the period beginning on the date of grant and ending on the date an individual is eligible for retirement and the award vests. Stock Options Changes in stock options for 2018 are summarized as follows: Options Weighted Average Exercise Price Weighted Average Remaining Years Contractual Term Aggregate Intrinsic Value Outstanding as of January 1, 2018 347,900 $ 33.49 Exercised 115,967 $ 33.49 Canceled/Forfeited — $ — Outstanding as of December 31, 2018 231,933 $ 33.49 1.0 $ 4,304,676 Exercisable at December 31, 2018 231,933 $ 33.49 1.0 $ 4,304,676 The fair value of each option grant is estimated on the date of grant using the Black-Scholes option-pricing model. There were no option grants in 2018 , 2017 and 2016 . Activity for options exercised for the years ended December 31, 2018 , 2017 and 2016 is shown below: 2018 2017 2016 Millions Total Intrinsic Value of Options Exercised $ 2 $ 5 $ 7 Cash Received from Options Exercised $ 4 $ 26 $ 22 Tax Benefit Realized from Options Exercised $ — $ — $ 1 No options were vested during the years ended December 31, 2018 , 2017 and 2016 . Restricted Stock Units Changes in restricted stock units for the year ended December 31, 2018 are summarized as follows: Shares Weighted Average Grant Date Fair Value Weighted Average Remaining Years Contractual Term Aggregate Intrinsic Value Non-vested as of January 1, 2018 213,899 $ 42.32 Granted 277,261 $ 49.34 Vested 220,105 $ 46.02 Canceled/Forfeited 13,472 $ 44.94 Non-vested as of December 31, 2018 257,583 $ 46.58 1.2 $ 13,407,195 The weighted average grant date fair value per share for restricted stock units during the years ended December 31, 2018 , 2017 and 2016 was $49.34 , $44.33 and $42.28 per share, respectively. The total intrinsic value of restricted stock units distributed during the years ended December 31, 2018 , 2017 and 2016 was $12 million , $13 million and $17 million , respectively. As of December 31, 2018 , there was approximately $5 million of unrecognized compensation cost related to the restricted stock units, which is expected to be recognized over a weighted average period of 1.2 years. Dividend equivalents units of 26,987 accrued on the restricted stock units during the year. Performance Share Units Changes in performance share units for the year ended December 31, 2018 are summarized as follows: Shares Weighted Average Grant Date Fair Value Weighted Average Remaining Years Contractual Term Aggregate Intrinsic Value Non-vested as of January 1, 2018 332,461 $ 45.29 Granted 378,800 $ 54.95 Vested 310,425 $ 49.63 Canceled/Forfeited 23,295 $ 48.57 Non-vested as of December 31, 2018 377,541 $ 51.94 1.7 $ 19,651,009 The weighted average grant date fair value per share for performance share units during the years ended December 31, 2018 , 2017 and 2016 was $54.95 , $45.02 and $45.97 per share, respectively. The total intrinsic value of performance share units distributed during the years ended December 31, 2018 , 2017 and 2016 was $17 million , $18 million and $17 million , respectively. As of December 31, 2018 , there was approximately $21 million of unrecognized compensation cost related to the performance share units, which is expected to be recognized over a weighted average period of 1.7 years. Dividend equivalents units of 37,156 accrued on the performance share units during the year. Outside Directors Under the Directors Equity Plan, annually, on the first business day of May, each non-employee member of the Board of Directors is awarded stock units based on the amount of annual compensation to be paid at the closing price of PSEG common stock on that date. Dividend equivalents are credited quarterly and distributions will commence upon the director leaving the Board as specified by him/her in accordance with the provisions of the Directors Equity Plan. The fair value of these awards is recorded as compensation expense in the Consolidated Statements of Operations. Compensation expense for the plan was immaterial for each of the years ended December 31, 2018 , 2017 and 2016 . Employee Stock Purchase Plan (ESPP) PSEG maintains an ESPP for all eligible employees of PSEG and its subsidiaries. Under the ESPP, shares of PSEG common stock may be purchased at 95% of the fair market value for represented employees and 90% for non-represented employees through payroll deductions. Dividends will be reinvested for all employees at 95% of the fair market price unless the participant elects to receive a cash dividend. All employees are required to hold the shares purchased under the ESPP for at least three months from the purchase date. In any year, employees may purchase shares having a value not exceeding 10% of their base pay. Compensation expense recognized under this program was immaterial for each of the years ended December 31, 2018 , 2017 and 2016 . During the years ended December 31, 2018 , 2017 and 2016 , employees purchased 286,559 shares, 288,527 shares and 262,763 shares, respectively, at an average price of $47.44 , $42.07 and $40.70 per share, respectively. As of December 31, 2018 , 2.9 million shares were available for future issuance under this plan.
PSE&G [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock Based Compensation	Stock Based Compensation PSEG’s Amended and Restated 2004 Long-Term Incentive Plan (LTIP) is a broad-based equity compensation program that provides for grants of various long-term incentive compensation awards, such as stock options, stock appreciation rights, performance share units, restricted stock, restricted stock units, cash awards or any combination thereof. The types of long-term incentive awards that have been granted and remain outstanding under the LTIP are non-qualified options to purchase shares of PSEG’s common stock, restricted stock unit awards and performance share unit awards. The type of equity award that is granted and the details of that award may vary from time to time and is subject to the approval of the Organization and Compensation Committee of PSEG’s Board of Directors (O&CC), the LTIP’s administrative committee. The LTIP currently provides for the issuance of equity awards with respect to approximately 16 million shares of common stock. As of December 31, 2018 , there were approximately 13 million shares available for future awards under the LTIP. Stock Options Under the LTIP, non-qualified options to acquire shares of PSEG common stock may be granted to officers and other key employees selected by the O&CC. Option awards are granted with an exercise price equal to the market price of PSEG’s common stock at the grant date. The options generally vest over four years of continuous service. Vesting schedules may be accelerated upon the occurrence of certain events, such as a change-in-control (unless substituted with an equity award of equal value), retirement, death or disability. Options are exercisable over a period of time designated by the O&CC (but not prior to one year or longer than ten years from the date of grant) and are subject to such other terms and conditions as the O&CC determines. Payment by option holders upon exercise of an option may be made in cash or, with the consent of the O&CC, by delivering previously acquired shares of PSEG common stock. No options have been granted since 2009. Restricted Stock Units Under the LTIP, PSEG has granted restricted stock unit awards to officers and other key employees. These awards, which are bookkeeping entries only, are subject to risk of forfeiture until vested by continued employment. Until distributed, the units are credited with dividend equivalents proportionate to the dividends paid on PSEG common stock. Distributions are made in shares of common stock. The restricted stock unit grants for 2018 and 2017 generally vest at the end of three years. Vesting may be accelerated (pro-rated basis or full vesting) upon certain events such as change-in-control, retirement, disability or death. Performance Share Units Under the LTIP, PSEG has granted performance share units to officers and other key employees. These provide for distribution in shares of PSEG common stock based on achievement of certain financial goals over a three -year performance period. Following the end of the performance period, the payout varies from 0% to 200% of the number of performance units granted depending on PSEG’s performance with respect to certain financial targets, including targets related to comparative performance against other companies in a peer group of energy companies. The performance share units are credited with dividend equivalents proportionate to the dividends paid on PSEG common stock. Distributions are made in shares of common stock. Vesting may be accelerated on a pro-rated basis for the period of the employee’s service during the performance period as a result of certain events, such as change-in-control, retirement, death or disability. Stock-Based Compensation PSEG recognizes compensation expense for stock options based on their grant date fair values, which are determined using the Black-Scholes option-pricing model. Stock option awards are expensed on a tranche-specific basis over the requisite service period of the award. Ultimately, compensation expense for stock options is recognized for awards that vest. PSEG recognizes compensation expense for restricted stock units over the vesting period based on the grant date fair value of the shares, which is equal to the market price of PSEG’s common stock on the date of the grant. PSEG recognizes compensation expense for the total shareholder return target for its performance share unit awards based on the grant date fair values of the award, which are determined using the Monte Carlo model. The accrual of compensation cost is based on the probable achievement of the performance conditions, which result in a payout from 0% to 200% of the initial grant. PSEG recognizes compensation expense for the return on invested capital target for its performance share units based on the grant date fair value of the awards, which is equal to the market price of PSEG’s common stock on the date of the grant. The accrual during the year of grant is estimated at 100% of the original grant. Such accrual may be adjusted to reflect the actual outcome. 2018 2017 2016 Millions Compensation Cost included in Operation and Maintenance Expense $ 30 $ 31 $ 29 Income Tax Benefit Recognized in Consolidated Statement of Operations $ 9 $ 13 $ 12 For 2018 , 2017 and 2016 the excess tax benefit of $3 million , $4 million and $4 million , respectively was included as financing cash flows on the Consolidated Statements of Cash Flow. PSEG recognizes compensation cost of awards issued over the shorter of the original vesting period or the period beginning on the date of grant and ending on the date an individual is eligible for retirement and the award vests. Stock Options Changes in stock options for 2018 are summarized as follows: Options Weighted Average Exercise Price Weighted Average Remaining Years Contractual Term Aggregate Intrinsic Value Outstanding as of January 1, 2018 347,900 $ 33.49 Exercised 115,967 $ 33.49 Canceled/Forfeited — $ — Outstanding as of December 31, 2018 231,933 $ 33.49 1.0 $ 4,304,676 Exercisable at December 31, 2018 231,933 $ 33.49 1.0 $ 4,304,676 The fair value of each option grant is estimated on the date of grant using the Black-Scholes option-pricing model. There were no option grants in 2018 , 2017 and 2016 . Activity for options exercised for the years ended December 31, 2018 , 2017 and 2016 is shown below: 2018 2017 2016 Millions Total Intrinsic Value of Options Exercised $ 2 $ 5 $ 7 Cash Received from Options Exercised $ 4 $ 26 $ 22 Tax Benefit Realized from Options Exercised $ — $ — $ 1 No options were vested during the years ended December 31, 2018 , 2017 and 2016 . Restricted Stock Units Changes in restricted stock units for the year ended December 31, 2018 are summarized as follows: Shares Weighted Average Grant Date Fair Value Weighted Average Remaining Years Contractual Term Aggregate Intrinsic Value Non-vested as of January 1, 2018 213,899 $ 42.32 Granted 277,261 $ 49.34 Vested 220,105 $ 46.02 Canceled/Forfeited 13,472 $ 44.94 Non-vested as of December 31, 2018 257,583 $ 46.58 1.2 $ 13,407,195 The weighted average grant date fair value per share for restricted stock units during the years ended December 31, 2018 , 2017 and 2016 was $49.34 , $44.33 and $42.28 per share, respectively. The total intrinsic value of restricted stock units distributed during the years ended December 31, 2018 , 2017 and 2016 was $12 million , $13 million and $17 million , respectively. As of December 31, 2018 , there was approximately $5 million of unrecognized compensation cost related to the restricted stock units, which is expected to be recognized over a weighted average period of 1.2 years. Dividend equivalents units of 26,987 accrued on the restricted stock units during the year. Performance Share Units Changes in performance share units for the year ended December 31, 2018 are summarized as follows: Shares Weighted Average Grant Date Fair Value Weighted Average Remaining Years Contractual Term Aggregate Intrinsic Value Non-vested as of January 1, 2018 332,461 $ 45.29 Granted 378,800 $ 54.95 Vested 310,425 $ 49.63 Canceled/Forfeited 23,295 $ 48.57 Non-vested as of December 31, 2018 377,541 $ 51.94 1.7 $ 19,651,009 The weighted average grant date fair value per share for performance share units during the years ended December 31, 2018 , 2017 and 2016 was $54.95 , $45.02 and $45.97 per share, respectively. The total intrinsic value of performance share units distributed during the years ended December 31, 2018 , 2017 and 2016 was $17 million , $18 million and $17 million , respectively. As of December 31, 2018 , there was approximately $21 million of unrecognized compensation cost related to the performance share units, which is expected to be recognized over a weighted average period of 1.7 years. Dividend equivalents units of 37,156 accrued on the performance share units during the year. Outside Directors Under the Directors Equity Plan, annually, on the first business day of May, each non-employee member of the Board of Directors is awarded stock units based on the amount of annual compensation to be paid at the closing price of PSEG common stock on that date. Dividend equivalents are credited quarterly and distributions will commence upon the director leaving the Board as specified by him/her in accordance with the provisions of the Directors Equity Plan. The fair value of these awards is recorded as compensation expense in the Consolidated Statements of Operations. Compensation expense for the plan was immaterial for each of the years ended December 31, 2018 , 2017 and 2016 . Employee Stock Purchase Plan (ESPP) PSEG maintains an ESPP for all eligible employees of PSEG and its subsidiaries. Under the ESPP, shares of PSEG common stock may be purchased at 95% of the fair market value for represented employees and 90% for non-represented employees through payroll deductions. Dividends will be reinvested for all employees at 95% of the fair market price unless the participant elects to receive a cash dividend. All employees are required to hold the shares purchased under the ESPP for at least three months from the purchase date. In any year, employees may purchase shares having a value not exceeding 10% of their base pay. Compensation expense recognized under this program was immaterial for each of the years ended December 31, 2018 , 2017 and 2016 . During the years ended December 31, 2018 , 2017 and 2016 , employees purchased 286,559 shares, 288,527 shares and 262,763 shares, respectively, at an average price of $47.44 , $42.07 and $40.70 per share, respectively. As of December 31, 2018 , 2.9 million shares were available for future issuance under this plan.
Power [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock Based Compensation	Stock Based Compensation PSEG’s Amended and Restated 2004 Long-Term Incentive Plan (LTIP) is a broad-based equity compensation program that provides for grants of various long-term incentive compensation awards, such as stock options, stock appreciation rights, performance share units, restricted stock, restricted stock units, cash awards or any combination thereof. The types of long-term incentive awards that have been granted and remain outstanding under the LTIP are non-qualified options to purchase shares of PSEG’s common stock, restricted stock unit awards and performance share unit awards. The type of equity award that is granted and the details of that award may vary from time to time and is subject to the approval of the Organization and Compensation Committee of PSEG’s Board of Directors (O&CC), the LTIP’s administrative committee. The LTIP currently provides for the issuance of equity awards with respect to approximately 16 million shares of common stock. As of December 31, 2018 , there were approximately 13 million shares available for future awards under the LTIP. Stock Options Under the LTIP, non-qualified options to acquire shares of PSEG common stock may be granted to officers and other key employees selected by the O&CC. Option awards are granted with an exercise price equal to the market price of PSEG’s common stock at the grant date. The options generally vest over four years of continuous service. Vesting schedules may be accelerated upon the occurrence of certain events, such as a change-in-control (unless substituted with an equity award of equal value), retirement, death or disability. Options are exercisable over a period of time designated by the O&CC (but not prior to one year or longer than ten years from the date of grant) and are subject to such other terms and conditions as the O&CC determines. Payment by option holders upon exercise of an option may be made in cash or, with the consent of the O&CC, by delivering previously acquired shares of PSEG common stock. No options have been granted since 2009. Restricted Stock Units Under the LTIP, PSEG has granted restricted stock unit awards to officers and other key employees. These awards, which are bookkeeping entries only, are subject to risk of forfeiture until vested by continued employment. Until distributed, the units are credited with dividend equivalents proportionate to the dividends paid on PSEG common stock. Distributions are made in shares of common stock. The restricted stock unit grants for 2018 and 2017 generally vest at the end of three years. Vesting may be accelerated (pro-rated basis or full vesting) upon certain events such as change-in-control, retirement, disability or death. Performance Share Units Under the LTIP, PSEG has granted performance share units to officers and other key employees. These provide for distribution in shares of PSEG common stock based on achievement of certain financial goals over a three -year performance period. Following the end of the performance period, the payout varies from 0% to 200% of the number of performance units granted depending on PSEG’s performance with respect to certain financial targets, including targets related to comparative performance against other companies in a peer group of energy companies. The performance share units are credited with dividend equivalents proportionate to the dividends paid on PSEG common stock. Distributions are made in shares of common stock. Vesting may be accelerated on a pro-rated basis for the period of the employee’s service during the performance period as a result of certain events, such as change-in-control, retirement, death or disability. Stock-Based Compensation PSEG recognizes compensation expense for stock options based on their grant date fair values, which are determined using the Black-Scholes option-pricing model. Stock option awards are expensed on a tranche-specific basis over the requisite service period of the award. Ultimately, compensation expense for stock options is recognized for awards that vest. PSEG recognizes compensation expense for restricted stock units over the vesting period based on the grant date fair value of the shares, which is equal to the market price of PSEG’s common stock on the date of the grant. PSEG recognizes compensation expense for the total shareholder return target for its performance share unit awards based on the grant date fair values of the award, which are determined using the Monte Carlo model. The accrual of compensation cost is based on the probable achievement of the performance conditions, which result in a payout from 0% to 200% of the initial grant. PSEG recognizes compensation expense for the return on invested capital target for its performance share units based on the grant date fair value of the awards, which is equal to the market price of PSEG’s common stock on the date of the grant. The accrual during the year of grant is estimated at 100% of the original grant. Such accrual may be adjusted to reflect the actual outcome. 2018 2017 2016 Millions Compensation Cost included in Operation and Maintenance Expense $ 30 $ 31 $ 29 Income Tax Benefit Recognized in Consolidated Statement of Operations $ 9 $ 13 $ 12 For 2018 , 2017 and 2016 the excess tax benefit of $3 million , $4 million and $4 million , respectively was included as financing cash flows on the Consolidated Statements of Cash Flow. PSEG recognizes compensation cost of awards issued over the shorter of the original vesting period or the period beginning on the date of grant and ending on the date an individual is eligible for retirement and the award vests. Stock Options Changes in stock options for 2018 are summarized as follows: Options Weighted Average Exercise Price Weighted Average Remaining Years Contractual Term Aggregate Intrinsic Value Outstanding as of January 1, 2018 347,900 $ 33.49 Exercised 115,967 $ 33.49 Canceled/Forfeited — $ — Outstanding as of December 31, 2018 231,933 $ 33.49 1.0 $ 4,304,676 Exercisable at December 31, 2018 231,933 $ 33.49 1.0 $ 4,304,676 The fair value of each option grant is estimated on the date of grant using the Black-Scholes option-pricing model. There were no option grants in 2018 , 2017 and 2016 . Activity for options exercised for the years ended December 31, 2018 , 2017 and 2016 is shown below: 2018 2017 2016 Millions Total Intrinsic Value of Options Exercised $ 2 $ 5 $ 7 Cash Received from Options Exercised $ 4 $ 26 $ 22 Tax Benefit Realized from Options Exercised $ — $ — $ 1 No options were vested during the years ended December 31, 2018 , 2017 and 2016 . Restricted Stock Units Changes in restricted stock units for the year ended December 31, 2018 are summarized as follows: Shares Weighted Average Grant Date Fair Value Weighted Average Remaining Years Contractual Term Aggregate Intrinsic Value Non-vested as of January 1, 2018 213,899 $ 42.32 Granted 277,261 $ 49.34 Vested 220,105 $ 46.02 Canceled/Forfeited 13,472 $ 44.94 Non-vested as of December 31, 2018 257,583 $ 46.58 1.2 $ 13,407,195 The weighted average grant date fair value per share for restricted stock units during the years ended December 31, 2018 , 2017 and 2016 was $49.34 , $44.33 and $42.28 per share, respectively. The total intrinsic value of restricted stock units distributed during the years ended December 31, 2018 , 2017 and 2016 was $12 million , $13 million and $17 million , respectively. As of December 31, 2018 , there was approximately $5 million of unrecognized compensation cost related to the restricted stock units, which is expected to be recognized over a weighted average period of 1.2 years. Dividend equivalents units of 26,987 accrued on the restricted stock units during the year. Performance Share Units Changes in performance share units for the year ended December 31, 2018 are summarized as follows: Shares Weighted Average Grant Date Fair Value Weighted Average Remaining Years Contractual Term Aggregate Intrinsic Value Non-vested as of January 1, 2018 332,461 $ 45.29 Granted 378,800 $ 54.95 Vested 310,425 $ 49.63 Canceled/Forfeited 23,295 $ 48.57 Non-vested as of December 31, 2018 377,541 $ 51.94 1.7 $ 19,651,009 The weighted average grant date fair value per share for performance share units during the years ended December 31, 2018 , 2017 and 2016 was $54.95 , $45.02 and $45.97 per share, respectively. The total intrinsic value of performance share units distributed during the years ended December 31, 2018 , 2017 and 2016 was $17 million , $18 million and $17 million , respectively. As of December 31, 2018 , there was approximately $21 million of unrecognized compensation cost related to the performance share units, which is expected to be recognized over a weighted average period of 1.7 years. Dividend equivalents units of 37,156 accrued on the performance share units during the year. Outside Directors Under the Directors Equity Plan, annually, on the first business day of May, each non-employee member of the Board of Directors is awarded stock units based on the amount of annual compensation to be paid at the closing price of PSEG common stock on that date. Dividend equivalents are credited quarterly and distributions will commence upon the director leaving the Board as specified by him/her in accordance with the provisions of the Directors Equity Plan. The fair value of these awards is recorded as compensation expense in the Consolidated Statements of Operations. Compensation expense for the plan was immaterial for each of the years ended December 31, 2018 , 2017 and 2016 . Employee Stock Purchase Plan (ESPP) PSEG maintains an ESPP for all eligible employees of PSEG and its subsidiaries. Under the ESPP, shares of PSEG common stock may be purchased at 95% of the fair market value for represented employees and 90% for non-represented employees through payroll deductions. Dividends will be reinvested for all employees at 95% of the fair market price unless the participant elects to receive a cash dividend. All employees are required to hold the shares purchased under the ESPP for at least three months from the purchase date. In any year, employees may purchase shares having a value not exceeding 10% of their base pay. Compensation expense recognized under this program was immaterial for each of the years ended December 31, 2018 , 2017 and 2016 . During the years ended December 31, 2018 , 2017 and 2016 , employees purchased 286,559 shares, 288,527 shares and 262,763 shares, respectively, at an average price of $47.44 , $42.07 and $40.70 per share, respectively. As of December 31, 2018 , 2.9 million shares were available for future issuance under this plan.

Other Income and Deductions

Other Income and Deductions	12 Months Ended
	Dec. 31, 2018
Component of Other Income [Line Items]
Other Income and Deductions	Other Income (Deductions) PSE&G Power Other (A) Consolidated Total Millions Year Ended December 31, 2018 NDT Fund Interest and Dividends $ — $ 52 $ — $ 52 Allowance for Funds Used During Construction 54 — — 54 Solar Loan Interest 18 — — 18 Donations — — (17 ) (17 ) Other 8 (31 ) 1 (22 ) Total Other Income (Deductions) $ 80 $ 21 $ (16 ) $ 85 Year Ended December 31, 2017 NDT Fund Interest and Dividends $ — $ 45 $ — $ 45 Allowance for Funds Used During Construction 56 — — 56 Solar Loan Interest 21 — — 21 Donations (1 ) (2 ) (25 ) (28 ) Other 9 (23 ) 2 (12 ) Total Other Income (Deductions) $ 85 $ 20 $ (23 ) $ 82 Year Ended December 31, 2016 NDT Fund Interest and Dividends $ — $ 43 $ — $ 43 Allowance for Funds Used During Construction 49 — — 49 Solar Loan Interest 22 — — 22 Donations (1 ) (1 ) — (2 ) Other 9 (19 ) — (10 ) Total Other Income (Deductions) $ 79 $ 23 $ — $ 102 (A) Other consists of activity at PSEG (as parent company), Energy Holdings, Services, PSEG LI and intercompany eliminations.
PSE&G [Member]
Component of Other Income [Line Items]
Other Income and Deductions	Other Income (Deductions) PSE&G Power Other (A) Consolidated Total Millions Year Ended December 31, 2018 NDT Fund Interest and Dividends $ — $ 52 $ — $ 52 Allowance for Funds Used During Construction 54 — — 54 Solar Loan Interest 18 — — 18 Donations — — (17 ) (17 ) Other 8 (31 ) 1 (22 ) Total Other Income (Deductions) $ 80 $ 21 $ (16 ) $ 85 Year Ended December 31, 2017 NDT Fund Interest and Dividends $ — $ 45 $ — $ 45 Allowance for Funds Used During Construction 56 — — 56 Solar Loan Interest 21 — — 21 Donations (1 ) (2 ) (25 ) (28 ) Other 9 (23 ) 2 (12 ) Total Other Income (Deductions) $ 85 $ 20 $ (23 ) $ 82 Year Ended December 31, 2016 NDT Fund Interest and Dividends $ — $ 43 $ — $ 43 Allowance for Funds Used During Construction 49 — — 49 Solar Loan Interest 22 — — 22 Donations (1 ) (1 ) — (2 ) Other 9 (19 ) — (10 ) Total Other Income (Deductions) $ 79 $ 23 $ — $ 102 (A) Other consists of activity at PSEG (as parent company), Energy Holdings, Services, PSEG LI and intercompany eliminations.
Power [Member]
Component of Other Income [Line Items]
Other Income and Deductions	Other Income (Deductions) PSE&G Power Other (A) Consolidated Total Millions Year Ended December 31, 2018 NDT Fund Interest and Dividends $ — $ 52 $ — $ 52 Allowance for Funds Used During Construction 54 — — 54 Solar Loan Interest 18 — — 18 Donations — — (17 ) (17 ) Other 8 (31 ) 1 (22 ) Total Other Income (Deductions) $ 80 $ 21 $ (16 ) $ 85 Year Ended December 31, 2017 NDT Fund Interest and Dividends $ — $ 45 $ — $ 45 Allowance for Funds Used During Construction 56 — — 56 Solar Loan Interest 21 — — 21 Donations (1 ) (2 ) (25 ) (28 ) Other 9 (23 ) 2 (12 ) Total Other Income (Deductions) $ 85 $ 20 $ (23 ) $ 82 Year Ended December 31, 2016 NDT Fund Interest and Dividends $ — $ 43 $ — $ 43 Allowance for Funds Used During Construction 49 — — 49 Solar Loan Interest 22 — — 22 Donations (1 ) (1 ) — (2 ) Other 9 (19 ) — (10 ) Total Other Income (Deductions) $ 79 $ 23 $ — $ 102 (A) Other consists of activity at PSEG (as parent company), Energy Holdings, Services, PSEG LI and intercompany eliminations.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2018
Income Taxes [Line Items]
Income Taxes	Income Taxes A reconciliation of reported income tax expense for PSEG with the amount computed by multiplying pre-tax income by the statutory federal income tax rate of 21% in 2018 and 35% in 2017 and 2016 is as follows: Years Ended December 31, PSEG 2018 2017 2016 Millions Net Income $ 1,438 $ 1,574 $ 887 Income Taxes: Operating Income: Current (Benefit) Expense: Federal $ (97 ) $ 86 $ (74 ) State 83 (31 ) 61 Total Current (14 ) 55 (13 ) Deferred Expense (Benefit): Federal 373 (482 ) 311 State 71 92 28 Total Deferred 444 (390 ) 339 Investment Tax Credit (ITC) (13 ) 29 85 Total Income Tax Expense (Benefit) $ 417 $ (306 ) $ 411 Pre-Tax Income $ 1,855 $ 1,268 $ 1,298 Tax Computed at Statutory Rate 21% in 2018 and 35% in 2017 and 2016 $ 390 $ 444 $ 454 Increase (Decrease) Attributable to Flow-Through of Certain Tax Adjustments: State Income Taxes (net of federal income tax) 123 36 56 Uncertain Tax Positions (24 ) (3 ) (31 ) Manufacturing Deduction — (13 ) (17 ) NDT Fund (13 ) 19 3 Plant-Related Items (10 ) (23 ) (20 ) Tax Credits (16 ) (22 ) (25 ) Audit Settlement — 6 — Tax Adjustment Credit (30 ) — — Deferred Tax Expense (Benefit) - Tax Act 3 (755 ) — Other (6 ) 5 (9 ) Sub-Total 27 (750 ) (43 ) Total Income Tax Expense (Benefit) $ 417 $ (306 ) $ 411 Effective Income Tax Rate 22.5 % (24.1 )% 31.7 % The following is an analysis of deferred income taxes for PSEG: As of December 31, PSEG 2018 2017 Millions Deferred Income Taxes Assets: Noncurrent Regulatory Liability Excess Deferred Tax $ 606 $ 602 OPEB 163 217 Related to Uncertain Tax Position 71 142 Total Noncurrent Assets $ 840 $ 961 Liabilities: Noncurrent: Plant-Related Items $ 4,817 $ 4,257 New Jersey Corporate Business Tax 756 674 Leasing Activities 307 384 AROs and NDT Fund 196 233 Pension Costs 111 123 Taxes Recoverable Through Future Rates (net) 89 80 Other 12 171 Total Noncurrent Liabilities $ 6,288 $ 5,922 Summary of Accumulated Deferred Income Taxes: Net Noncurrent Deferred Income Tax Liabilities $ 5,448 $ 4,961 ITC 265 279 Net Total Noncurrent Deferred Income Taxes and ITC $ 5,713 $ 5,240 The deferred tax effect of certain assets and liabilities is presented in the table above net of the deferred tax effect associated with the respective regulatory deferrals. In December 2017, new tax legislation was enacted, reducing the statutory U.S. corporate income tax rate from a maximum of 35% to 21%, effective January 1, 2018. PSEG is subject to ASC 740, which requires that the effect on deferred tax assets and liabilities of a change in tax rates be recognized in the period the tax rate was enacted. A reconciliation of reported income tax expense for PSE&G with the amount computed by multiplying pre-tax income by the statutory federal income tax rate of 21% in 2018 and 35% in 2017 and 2016 is as follows: Years Ended December 31, PSE&G 2018 2017 2016 Millions Net Income $ 1,067 $ 973 $ 889 Income Taxes: Operating Income: Current (Benefit) Expense: Federal $ (62 ) $ (52 ) $ (153 ) State 1 (1 ) 10 Total Current (61 ) (53 ) (143 ) Deferred Expense: Federal 287 492 551 State 122 129 102 Total Deferred 409 621 653 ITC (4 ) (5 ) 5 Total Income Tax Expense $ 344 $ 563 $ 515 Pre-Tax Income $ 1,411 $ 1,536 $ 1,404 Tax Computed at Statutory Rate 21% in 2018 and 35% in 2017 and 2016 $ 296 $ 538 $ 491 Increase (Decrease) Attributable to Flow-Through of Certain Tax Adjustments: State Income Taxes (net of federal income tax) 98 83 72 Uncertain Tax Positions (1 ) (9 ) (18 ) Plant-Related Items (10 ) (23 ) (20 ) Tax Credits (8 ) (9 ) (7 ) Tax Adjustment Credit (30 ) — — Deferred Tax Benefit - Tax Act — (10 ) — Other (1 ) (7 ) (3 ) Sub-Total 48 25 24 Total Income Tax Expense $ 344 $ 563 $ 515 Effective Income Tax Rate 24.4 % 36.7 % 36.7 % The following is an analysis of deferred income taxes for PSE&G: As of December 31, PSE&G 2018 2017 Millions Deferred Income Taxes Assets: Noncurrent: Regulatory Liability Excess Deferred Tax $ 606 $ 602 OPEB 114 116 Total Noncurrent Assets $ 720 $ 718 Liabilities: Noncurrent: Plant-Related Items $ 3,622 $ 3,311 New Jersey Corporate Business Tax 486 378 Pension Costs 159 152 Conservation Costs 36 24 Taxes Recoverable Through Future Rates (net) 89 80 Other 84 86 Total Noncurrent Liabilities $ 4,476 $ 4,031 Summary of Accumulated Deferred Income Taxes: Net Noncurrent Deferred Income Tax Liabilities $ 3,756 $ 3,313 ITC 74 78 Net Total Noncurrent Deferred Income Taxes and ITC $ 3,830 $ 3,391 The deferred tax effect of certain assets and liabilities is presented in the table above net of the deferred tax effect associated with the respective regulatory deferrals. In December 2017, new tax legislation was enacted, reducing the statutory U.S. corporate income tax rate from a maximum of 35% to 21%, effective January 1, 2018. PSE&G is subject to ASC 740, which requires that the effect on deferred tax assets and liabilities of a change in tax rates be recognized in the period the tax rate was enacted. A reconciliation of reported income tax expense for Power with the amount computed by multiplying pre-tax income by the statutory federal income tax rate of 21% in 2018 and 35% in 2017 and 2016 is as follows: Years Ended December 31, Power 2018 2017 2016 Millions Net Income $ 365 $ 479 $ 18 Income Taxes: Operating Income: Current (Benefit) Expense: Federal $ (164 ) $ 95 $ 107 State 24 (17 ) 40 Total Current (140 ) 78 147 Deferred Expense (Benefit): Federal 214 (804 ) (222 ) State 1 (37 ) (68 ) Total Deferred 215 (841 ) (290 ) ITC (9 ) 34 82 Total Income Tax Expense (Benefit) $ 66 $ (729 ) $ (61 ) Pre-Tax Income (Loss) $ 431 $ (250 ) $ (43 ) Tax Computed at Statutory Rate 21% in 2018 and 35% in 2017 and 2016 $ 91 $ (88 ) $ (15 ) Increase (Decrease) Attributable to Flow-Through of Certain Tax Adjustments: State Income Taxes (net of federal income tax) 21 (36 ) (18 ) Manufacturing Deduction — (13 ) (17 ) NDT Fund (13 ) 19 3 Tax Credits (7 ) (12 ) (18 ) Uncertain Tax Positions (24 ) 7 9 Audit Settlement — 1 — Deferred Tax Benefit - Tax Act (1 ) (610 ) — Other (1 ) 3 (5 ) Sub-Total (25 ) (641 ) (46 ) Total Income Tax Expense (Benefit) $ 66 $ (729 ) $ (61 ) Effective Income Tax Rate 15.3 % 291.6 % 141.9 % The following is an analysis of deferred income taxes for Power: As of December 31, Power 2018 2017 Millions Deferred Income Taxes Assets: Noncurrent: Related to Uncertain Tax Positions $ 60 $ 45 Pension Costs 52 40 Contractual Liabilities & Environmental Costs 9 12 Other 98 93 Total Noncurrent Assets $ 219 $ 190 Liabilities: Noncurrent: Plant-Related Items $ 1,189 $ 935 AROs and NDT Fund 197 235 New Jersey Corporate Business Tax 260 225 Total Noncurrent Liabilities $ 1,646 $ 1,395 Summary of Accumulated Deferred Income Taxes: Net Noncurrent Deferred Income Tax Liabilities $ 1,427 $ 1,205 ITC 192 201 Net Total Noncurrent Deferred Income Taxes and ITC $ 1,619 $ 1,406 PSEG, PSE&G and Power each provide deferred taxes at the enacted statutory tax rate for all temporary differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities irrespective of the treatment for rate-making purposes. Management believes that it is probable that the accumulated tax benefits that previously have been treated as a flow-through item to PSE&G customers will be recovered from or refunded to PSE&G’s customers in the future. See Note 7. Regulatory Assets and Liabilities . In December 2017, the U.S. government enacted comprehensive tax legislation. The Tax Act establishes new tax laws that took effect in 2018, including, but not limited to (1) reduction of the U.S. federal corporate tax rate from a maximum of 35% to 21%; (2) elimination of the corporate alternative minimum tax (AMT); (3) a new limitation on deductible interest expense; (4) the repeal of the manufacturing deduction; (5) limitations on the deductibility of certain executive compensation; and (6) limitations on net operating losses (NOLs) generated after December 31, 2017, to 80% of taxable income with an indefinite carryforward period. In addition, certain changes were made to the bonus depreciation rules that impacted 2017. In 2018 and beyond, it is expected that Power will be entitled to 100% expensing and bonus depreciation will no longer apply to PSE&G. As required under ASC 740, the ending 2017 deferred tax balances were adjusted to reflect the enacted lower tax rate, which resulted in a deferred tax benefit of $755 million , including $610 million related to Power and $149 million related to Energy Holdings (including other impacts related to the new tax legislation, PSEG’s net non-cash provisional earnings benefit was $745 million , including $588 million related to Power and $147 million related to Energy Holdings). There were no further material deferred tax benefits recorded in 2018 as a result of the Tax Act. In addition, PSE&G had excess deferred taxes of approximately $2.1 billion as of December 31, 2017 and recorded a $2.9 billion revenue impact of these excess deferred taxes as Regulatory Liabilities. In 2018, PSE&G recorded an additional $34 million of excess deferred taxes and a $46 million revenue impact of these excess taxes as Regulatory Liabilities associated with the 2017 return to accrual. PSEG, PSE&G and Power completed their accounting for the Tax Act based on the current regulatory guidance available at the end of the Staff Accounting Bulletin No. 118 measurement period, not to extend beyond one year from the enactment date of the Tax Act. The Tax Act has led to lower customer rates due to lower income tax expense recoveries and the BPU and FERC have approved our proposals to refund excess deferred income tax Regulatory Liabilities. See Note 7. Regulatory Assets and Liabilities for additional information. 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. 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. Further, in November 2018 the IRS issued Proposed Regulations addressing the interest disallowance rules contained in the Tax Act. For non-regulated businesses, these rules set a cap on the amount of interest that can be deducted in a given year. Any amount that is disallowed can be carried forward indefinitely. For 2018, PSEG and Power expect that a portion of the interest will be disallowed in the current period but realized in future periods. As a result, PSEG and Power recorded a deferred tax asset of $54 million and $8 million , respectively, in 2018. However, certain aspects of the proposed regulations are unclear; therefore, PSEG recorded taxes based on its interpretation of the relevant statute. Depreciation amounts recorded in 2018 were based on PSEG’s interpretation of the Tax Act and the depreciation rules contained in the Notice. Such amounts are subject to change based on several factors, including but not limited to, the IRS and state taxing authorities issuing final guidance and/or further clarification. Any further guidance or clarification could impact PSEG’s, PSE&G’s and Power’s financial statements. The Protecting Americans from Tax Hikes Act of 2015 (2015 Tax Act), among other provisions, included an extension of the bonus depreciation rules and the 30% investment tax credit for qualified property placed into service after 2016. Qualified property that is placed into service from January 1, 2015 through December 31, 2017 is eligible for the 50% bonus depreciation. The provisions of the 2015 Tax Act have generated significant cash tax benefits for PSEG, PSE&G and Power through tax benefits related to the accelerated depreciation. For the period beginning September 28, 2017, subject to the transition rules, the Tax Act has modified the bonus depreciation rules of the 2015 Tax Act. In 2018, Power generated a $14 million consolidated federal income tax NOL and PSE&G generated a $21 million New Jersey Corporate Business tax NOL. Both PSE&G and Power expect to fully realize their respective NOLs. There are no other material tax carryforwards in other jurisdictions. PSEG recorded the following amounts related to its unrecognized tax benefits, which were primarily comprised of amounts recorded for PSE&G, Power and Energy Holdings: 2018 PSEG PSE&G Power Energy Holdings Millions Total Amount of Unrecognized Tax Benefits as of January 1, 2018 $ 334 $ 135 $ 142 $ 53 Increases as a Result of Positions Taken in a Prior Period 11 4 4 3 Decreases as a Result of Positions Taken in a Prior Period (70 ) (31 ) (37 ) (2 ) Increases as a Result of Positions Taken during the Current Period 52 3 48 — Decreases as a Result of Positions Taken during the Current Period (3 ) (3 ) — — Decreases as a Result of Settlements with Taxing Authorities (6 ) — (6 ) — Decreases due to Lapses of Applicable Statute of Limitations — — — — Total Amount of Unrecognized Tax Benefits as of December 31, 2018 $ 318 $ 108 $ 151 $ 54 Accumulated Deferred Income Taxes Associated with Unrecognized Tax Benefits (173 ) (57 ) (104 ) (12 ) Regulatory Asset—Unrecognized Tax Benefits (46 ) (46 ) — — Total Amount of Unrecognized Tax Benefits that if Recognized, would Impact the Effective Tax Rate (including Interest and Penalties) $ 99 $ 5 $ 47 $ 42 2017 PSEG PSE&G Power Energy Holdings Millions Total Amount of Unrecognized Tax Benefits as of January 1, 2017 $ 328 $ 140 $ 128 $ 57 Increases as a Result of Positions Taken in a Prior Period 40 15 18 8 Decreases as a Result of Positions Taken in a Prior Period (32 ) (11 ) (10 ) (13 ) Increases as a Result of Positions Taken during the Current Period 12 5 6 1 Decreases as a Result of Positions Taken during the Current Period (1 ) (1 ) — — Decreases as a Result of Settlements with Taxing Authorities — — — — Decreases due to Lapses of Applicable Statute of Limitations (13 ) (13 ) — — Total Amount of Unrecognized Tax Benefits as of December 31, 2017 $ 334 $ 135 $ 142 $ 53 Accumulated Deferred Income Taxes Associated with Unrecognized Tax Benefits (157 ) (73 ) (72 ) (12 ) Regulatory Asset—Unrecognized Tax Benefits (56 ) (56 ) — — Total Amount of Unrecognized Tax Benefits that if Recognized, would Impact the Effective Tax Rate (including Interest and Penalties) $ 121 $ 6 $ 70 $ 41 2016 PSEG PSE&G Power Energy Holdings Millions Total Amount of Unrecognized Tax Benefits as of January 1, 2016 $ 386 $ 181 $ 111 $ 93 Increases as a Result of Positions Taken in a Prior Period 12 3 6 2 Decreases as a Result of Positions Taken in a Prior Period (62 ) (23 ) (1 ) (38 ) Increases as a Result of Positions Taken during the Current Period 19 6 12 — Decreases as a Result of Positions Taken during the Current Period — — — — Decreases as a Result of Settlements with Taxing Authorities — — — — Decreases due to Lapses of Applicable Statute of Limitations (27 ) (27 ) — — Total Amount of Unrecognized Tax Benefits as of December 31, 2016 $ 328 $ 140 $ 128 $ 57 Accumulated Deferred Income Taxes Associated with Unrecognized Tax Benefits (200 ) (106 ) (74 ) (20 ) Regulatory Asset—Unrecognized Tax Benefits (31 ) (31 ) — — Total Amount of Unrecognized Tax Benefits that if Recognized, would Impact the Effective Tax Rate (including Interest and Penalties) $ 97 $ 3 $ 54 $ 37 PSEG and its subsidiaries include accrued interest and penalties related to uncertain tax positions required to be recorded, as Income Tax Expense in the Consolidated Statements of Operations. Accumulated interest and penalties that are recorded on the Consolidated Balance Sheets on uncertain tax positions were as follows: Accumulated Interest and Penalties on Uncertain Tax Positions as of December 31, 2018 2017 2016 Millions PSE&G $ 12 $ 25 $ 22 Power 9 24 17 Energy Holdings 22 21 20 Total $ 43 $ 70 $ 59 It is reasonably possible that total unrecognized tax benefits will significantly increase or decrease within the next twelve months due to either agreements with various taxing authorities upon audit, the expiration of the Statute of Limitations, or other pending tax matters. These potential increases or decreases are as follows: Possible (Increase)/Decrease in Total Unrecognized Tax Benefits Over the next 12 Months Millions PSEG $ 112 PSE&G $ 62 Power $ 34 A description of income tax years that remain subject to examination by material jurisdictions, where an examination has not already concluded are: PSEG PSE&G Power United States Federal 2011-2017 N/A N/A New Jersey 2006-2017 2011-2017 N/A Pennsylvania 2015-2017 2015-2017 N/A Connecticut 2016-2017 N/A N/A California 2006-2017 N/A N/A New York 2017 N/A 2017 New Jersey State Tax Reform In July 2018, the State of New Jersey made changes to its income tax laws, including imposing a temporary surtax on allocated corporate taxable income of 2.5% effective January 1, 2018 and 2019 and 1.5% in 2020 and 2021, as well as requiring corporate taxpayers to file in a combined reporting group as defined under New Jersey law starting in 2019. Both provisions include an exemption for public utilities. 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. In 2018, PSEG’s non-utility business recorded $7 million of surtax as a result of these new provisions. This New Jersey tax legislation did not have a material impact on PSEG’s deferred income tax balance.
PSE&G [Member]
Income Taxes [Line Items]
Income Taxes	Income Taxes A reconciliation of reported income tax expense for PSEG with the amount computed by multiplying pre-tax income by the statutory federal income tax rate of 21% in 2018 and 35% in 2017 and 2016 is as follows: Years Ended December 31, PSEG 2018 2017 2016 Millions Net Income $ 1,438 $ 1,574 $ 887 Income Taxes: Operating Income: Current (Benefit) Expense: Federal $ (97 ) $ 86 $ (74 ) State 83 (31 ) 61 Total Current (14 ) 55 (13 ) Deferred Expense (Benefit): Federal 373 (482 ) 311 State 71 92 28 Total Deferred 444 (390 ) 339 Investment Tax Credit (ITC) (13 ) 29 85 Total Income Tax Expense (Benefit) $ 417 $ (306 ) $ 411 Pre-Tax Income $ 1,855 $ 1,268 $ 1,298 Tax Computed at Statutory Rate 21% in 2018 and 35% in 2017 and 2016 $ 390 $ 444 $ 454 Increase (Decrease) Attributable to Flow-Through of Certain Tax Adjustments: State Income Taxes (net of federal income tax) 123 36 56 Uncertain Tax Positions (24 ) (3 ) (31 ) Manufacturing Deduction — (13 ) (17 ) NDT Fund (13 ) 19 3 Plant-Related Items (10 ) (23 ) (20 ) Tax Credits (16 ) (22 ) (25 ) Audit Settlement — 6 — Tax Adjustment Credit (30 ) — — Deferred Tax Expense (Benefit) - Tax Act 3 (755 ) — Other (6 ) 5 (9 ) Sub-Total 27 (750 ) (43 ) Total Income Tax Expense (Benefit) $ 417 $ (306 ) $ 411 Effective Income Tax Rate 22.5 % (24.1 )% 31.7 % The following is an analysis of deferred income taxes for PSEG: As of December 31, PSEG 2018 2017 Millions Deferred Income Taxes Assets: Noncurrent Regulatory Liability Excess Deferred Tax $ 606 $ 602 OPEB 163 217 Related to Uncertain Tax Position 71 142 Total Noncurrent Assets $ 840 $ 961 Liabilities: Noncurrent: Plant-Related Items $ 4,817 $ 4,257 New Jersey Corporate Business Tax 756 674 Leasing Activities 307 384 AROs and NDT Fund 196 233 Pension Costs 111 123 Taxes Recoverable Through Future Rates (net) 89 80 Other 12 171 Total Noncurrent Liabilities $ 6,288 $ 5,922 Summary of Accumulated Deferred Income Taxes: Net Noncurrent Deferred Income Tax Liabilities $ 5,448 $ 4,961 ITC 265 279 Net Total Noncurrent Deferred Income Taxes and ITC $ 5,713 $ 5,240 The deferred tax effect of certain assets and liabilities is presented in the table above net of the deferred tax effect associated with the respective regulatory deferrals. In December 2017, new tax legislation was enacted, reducing the statutory U.S. corporate income tax rate from a maximum of 35% to 21%, effective January 1, 2018. PSEG is subject to ASC 740, which requires that the effect on deferred tax assets and liabilities of a change in tax rates be recognized in the period the tax rate was enacted. A reconciliation of reported income tax expense for PSE&G with the amount computed by multiplying pre-tax income by the statutory federal income tax rate of 21% in 2018 and 35% in 2017 and 2016 is as follows: Years Ended December 31, PSE&G 2018 2017 2016 Millions Net Income $ 1,067 $ 973 $ 889 Income Taxes: Operating Income: Current (Benefit) Expense: Federal $ (62 ) $ (52 ) $ (153 ) State 1 (1 ) 10 Total Current (61 ) (53 ) (143 ) Deferred Expense: Federal 287 492 551 State 122 129 102 Total Deferred 409 621 653 ITC (4 ) (5 ) 5 Total Income Tax Expense $ 344 $ 563 $ 515 Pre-Tax Income $ 1,411 $ 1,536 $ 1,404 Tax Computed at Statutory Rate 21% in 2018 and 35% in 2017 and 2016 $ 296 $ 538 $ 491 Increase (Decrease) Attributable to Flow-Through of Certain Tax Adjustments: State Income Taxes (net of federal income tax) 98 83 72 Uncertain Tax Positions (1 ) (9 ) (18 ) Plant-Related Items (10 ) (23 ) (20 ) Tax Credits (8 ) (9 ) (7 ) Tax Adjustment Credit (30 ) — — Deferred Tax Benefit - Tax Act — (10 ) — Other (1 ) (7 ) (3 ) Sub-Total 48 25 24 Total Income Tax Expense $ 344 $ 563 $ 515 Effective Income Tax Rate 24.4 % 36.7 % 36.7 % The following is an analysis of deferred income taxes for PSE&G: As of December 31, PSE&G 2018 2017 Millions Deferred Income Taxes Assets: Noncurrent: Regulatory Liability Excess Deferred Tax $ 606 $ 602 OPEB 114 116 Total Noncurrent Assets $ 720 $ 718 Liabilities: Noncurrent: Plant-Related Items $ 3,622 $ 3,311 New Jersey Corporate Business Tax 486 378 Pension Costs 159 152 Conservation Costs 36 24 Taxes Recoverable Through Future Rates (net) 89 80 Other 84 86 Total Noncurrent Liabilities $ 4,476 $ 4,031 Summary of Accumulated Deferred Income Taxes: Net Noncurrent Deferred Income Tax Liabilities $ 3,756 $ 3,313 ITC 74 78 Net Total Noncurrent Deferred Income Taxes and ITC $ 3,830 $ 3,391 The deferred tax effect of certain assets and liabilities is presented in the table above net of the deferred tax effect associated with the respective regulatory deferrals. In December 2017, new tax legislation was enacted, reducing the statutory U.S. corporate income tax rate from a maximum of 35% to 21%, effective January 1, 2018. PSE&G is subject to ASC 740, which requires that the effect on deferred tax assets and liabilities of a change in tax rates be recognized in the period the tax rate was enacted. A reconciliation of reported income tax expense for Power with the amount computed by multiplying pre-tax income by the statutory federal income tax rate of 21% in 2018 and 35% in 2017 and 2016 is as follows: Years Ended December 31, Power 2018 2017 2016 Millions Net Income $ 365 $ 479 $ 18 Income Taxes: Operating Income: Current (Benefit) Expense: Federal $ (164 ) $ 95 $ 107 State 24 (17 ) 40 Total Current (140 ) 78 147 Deferred Expense (Benefit): Federal 214 (804 ) (222 ) State 1 (37 ) (68 ) Total Deferred 215 (841 ) (290 ) ITC (9 ) 34 82 Total Income Tax Expense (Benefit) $ 66 $ (729 ) $ (61 ) Pre-Tax Income (Loss) $ 431 $ (250 ) $ (43 ) Tax Computed at Statutory Rate 21% in 2018 and 35% in 2017 and 2016 $ 91 $ (88 ) $ (15 ) Increase (Decrease) Attributable to Flow-Through of Certain Tax Adjustments: State Income Taxes (net of federal income tax) 21 (36 ) (18 ) Manufacturing Deduction — (13 ) (17 ) NDT Fund (13 ) 19 3 Tax Credits (7 ) (12 ) (18 ) Uncertain Tax Positions (24 ) 7 9 Audit Settlement — 1 — Deferred Tax Benefit - Tax Act (1 ) (610 ) — Other (1 ) 3 (5 ) Sub-Total (25 ) (641 ) (46 ) Total Income Tax Expense (Benefit) $ 66 $ (729 ) $ (61 ) Effective Income Tax Rate 15.3 % 291.6 % 141.9 % The following is an analysis of deferred income taxes for Power: As of December 31, Power 2018 2017 Millions Deferred Income Taxes Assets: Noncurrent: Related to Uncertain Tax Positions $ 60 $ 45 Pension Costs 52 40 Contractual Liabilities & Environmental Costs 9 12 Other 98 93 Total Noncurrent Assets $ 219 $ 190 Liabilities: Noncurrent: Plant-Related Items $ 1,189 $ 935 AROs and NDT Fund 197 235 New Jersey Corporate Business Tax 260 225 Total Noncurrent Liabilities $ 1,646 $ 1,395 Summary of Accumulated Deferred Income Taxes: Net Noncurrent Deferred Income Tax Liabilities $ 1,427 $ 1,205 ITC 192 201 Net Total Noncurrent Deferred Income Taxes and ITC $ 1,619 $ 1,406 PSEG, PSE&G and Power each provide deferred taxes at the enacted statutory tax rate for all temporary differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities irrespective of the treatment for rate-making purposes. Management believes that it is probable that the accumulated tax benefits that previously have been treated as a flow-through item to PSE&G customers will be recovered from or refunded to PSE&G’s customers in the future. See Note 7. Regulatory Assets and Liabilities . In December 2017, the U.S. government enacted comprehensive tax legislation. The Tax Act establishes new tax laws that took effect in 2018, including, but not limited to (1) reduction of the U.S. federal corporate tax rate from a maximum of 35% to 21%; (2) elimination of the corporate alternative minimum tax (AMT); (3) a new limitation on deductible interest expense; (4) the repeal of the manufacturing deduction; (5) limitations on the deductibility of certain executive compensation; and (6) limitations on net operating losses (NOLs) generated after December 31, 2017, to 80% of taxable income with an indefinite carryforward period. In addition, certain changes were made to the bonus depreciation rules that impacted 2017. In 2018 and beyond, it is expected that Power will be entitled to 100% expensing and bonus depreciation will no longer apply to PSE&G. As required under ASC 740, the ending 2017 deferred tax balances were adjusted to reflect the enacted lower tax rate, which resulted in a deferred tax benefit of $755 million , including $610 million related to Power and $149 million related to Energy Holdings (including other impacts related to the new tax legislation, PSEG’s net non-cash provisional earnings benefit was $745 million , including $588 million related to Power and $147 million related to Energy Holdings). There were no further material deferred tax benefits recorded in 2018 as a result of the Tax Act. In addition, PSE&G had excess deferred taxes of approximately $2.1 billion as of December 31, 2017 and recorded a $2.9 billion revenue impact of these excess deferred taxes as Regulatory Liabilities. In 2018, PSE&G recorded an additional $34 million of excess deferred taxes and a $46 million revenue impact of these excess taxes as Regulatory Liabilities associated with the 2017 return to accrual. PSEG, PSE&G and Power completed their accounting for the Tax Act based on the current regulatory guidance available at the end of the Staff Accounting Bulletin No. 118 measurement period, not to extend beyond one year from the enactment date of the Tax Act. The Tax Act has led to lower customer rates due to lower income tax expense recoveries and the BPU and FERC have approved our proposals to refund excess deferred income tax Regulatory Liabilities. See Note 7. Regulatory Assets and Liabilities for additional information. 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. 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. Further, in November 2018 the IRS issued Proposed Regulations addressing the interest disallowance rules contained in the Tax Act. For non-regulated businesses, these rules set a cap on the amount of interest that can be deducted in a given year. Any amount that is disallowed can be carried forward indefinitely. For 2018, PSEG and Power expect that a portion of the interest will be disallowed in the current period but realized in future periods. As a result, PSEG and Power recorded a deferred tax asset of $54 million and $8 million , respectively, in 2018. However, certain aspects of the proposed regulations are unclear; therefore, PSEG recorded taxes based on its interpretation of the relevant statute. Depreciation amounts recorded in 2018 were based on PSEG’s interpretation of the Tax Act and the depreciation rules contained in the Notice. Such amounts are subject to change based on several factors, including but not limited to, the IRS and state taxing authorities issuing final guidance and/or further clarification. Any further guidance or clarification could impact PSEG’s, PSE&G’s and Power’s financial statements. The Protecting Americans from Tax Hikes Act of 2015 (2015 Tax Act), among other provisions, included an extension of the bonus depreciation rules and the 30% investment tax credit for qualified property placed into service after 2016. Qualified property that is placed into service from January 1, 2015 through December 31, 2017 is eligible for the 50% bonus depreciation. The provisions of the 2015 Tax Act have generated significant cash tax benefits for PSEG, PSE&G and Power through tax benefits related to the accelerated depreciation. For the period beginning September 28, 2017, subject to the transition rules, the Tax Act has modified the bonus depreciation rules of the 2015 Tax Act. In 2018, Power generated a $14 million consolidated federal income tax NOL and PSE&G generated a $21 million New Jersey Corporate Business tax NOL. Both PSE&G and Power expect to fully realize their respective NOLs. There are no other material tax carryforwards in other jurisdictions. PSEG recorded the following amounts related to its unrecognized tax benefits, which were primarily comprised of amounts recorded for PSE&G, Power and Energy Holdings: 2018 PSEG PSE&G Power Energy Holdings Millions Total Amount of Unrecognized Tax Benefits as of January 1, 2018 $ 334 $ 135 $ 142 $ 53 Increases as a Result of Positions Taken in a Prior Period 11 4 4 3 Decreases as a Result of Positions Taken in a Prior Period (70 ) (31 ) (37 ) (2 ) Increases as a Result of Positions Taken during the Current Period 52 3 48 — Decreases as a Result of Positions Taken during the Current Period (3 ) (3 ) — — Decreases as a Result of Settlements with Taxing Authorities (6 ) — (6 ) — Decreases due to Lapses of Applicable Statute of Limitations — — — — Total Amount of Unrecognized Tax Benefits as of December 31, 2018 $ 318 $ 108 $ 151 $ 54 Accumulated Deferred Income Taxes Associated with Unrecognized Tax Benefits (173 ) (57 ) (104 ) (12 ) Regulatory Asset—Unrecognized Tax Benefits (46 ) (46 ) — — Total Amount of Unrecognized Tax Benefits that if Recognized, would Impact the Effective Tax Rate (including Interest and Penalties) $ 99 $ 5 $ 47 $ 42 2017 PSEG PSE&G Power Energy Holdings Millions Total Amount of Unrecognized Tax Benefits as of January 1, 2017 $ 328 $ 140 $ 128 $ 57 Increases as a Result of Positions Taken in a Prior Period 40 15 18 8 Decreases as a Result of Positions Taken in a Prior Period (32 ) (11 ) (10 ) (13 ) Increases as a Result of Positions Taken during the Current Period 12 5 6 1 Decreases as a Result of Positions Taken during the Current Period (1 ) (1 ) — — Decreases as a Result of Settlements with Taxing Authorities — — — — Decreases due to Lapses of Applicable Statute of Limitations (13 ) (13 ) — — Total Amount of Unrecognized Tax Benefits as of December 31, 2017 $ 334 $ 135 $ 142 $ 53 Accumulated Deferred Income Taxes Associated with Unrecognized Tax Benefits (157 ) (73 ) (72 ) (12 ) Regulatory Asset—Unrecognized Tax Benefits (56 ) (56 ) — — Total Amount of Unrecognized Tax Benefits that if Recognized, would Impact the Effective Tax Rate (including Interest and Penalties) $ 121 $ 6 $ 70 $ 41 2016 PSEG PSE&G Power Energy Holdings Millions Total Amount of Unrecognized Tax Benefits as of January 1, 2016 $ 386 $ 181 $ 111 $ 93 Increases as a Result of Positions Taken in a Prior Period 12 3 6 2 Decreases as a Result of Positions Taken in a Prior Period (62 ) (23 ) (1 ) (38 ) Increases as a Result of Positions Taken during the Current Period 19 6 12 — Decreases as a Result of Positions Taken during the Current Period — — — — Decreases as a Result of Settlements with Taxing Authorities — — — — Decreases due to Lapses of Applicable Statute of Limitations (27 ) (27 ) — — Total Amount of Unrecognized Tax Benefits as of December 31, 2016 $ 328 $ 140 $ 128 $ 57 Accumulated Deferred Income Taxes Associated with Unrecognized Tax Benefits (200 ) (106 ) (74 ) (20 ) Regulatory Asset—Unrecognized Tax Benefits (31 ) (31 ) — — Total Amount of Unrecognized Tax Benefits that if Recognized, would Impact the Effective Tax Rate (including Interest and Penalties) $ 97 $ 3 $ 54 $ 37 PSEG and its subsidiaries include accrued interest and penalties related to uncertain tax positions required to be recorded, as Income Tax Expense in the Consolidated Statements of Operations. Accumulated interest and penalties that are recorded on the Consolidated Balance Sheets on uncertain tax positions were as follows: Accumulated Interest and Penalties on Uncertain Tax Positions as of December 31, 2018 2017 2016 Millions PSE&G $ 12 $ 25 $ 22 Power 9 24 17 Energy Holdings 22 21 20 Total $ 43 $ 70 $ 59 It is reasonably possible that total unrecognized tax benefits will significantly increase or decrease within the next twelve months due to either agreements with various taxing authorities upon audit, the expiration of the Statute of Limitations, or other pending tax matters. These potential increases or decreases are as follows: Possible (Increase)/Decrease in Total Unrecognized Tax Benefits Over the next 12 Months Millions PSEG $ 112 PSE&G $ 62 Power $ 34 A description of income tax years that remain subject to examination by material jurisdictions, where an examination has not already concluded are: PSEG PSE&G Power United States Federal 2011-2017 N/A N/A New Jersey 2006-2017 2011-2017 N/A Pennsylvania 2015-2017 2015-2017 N/A Connecticut 2016-2017 N/A N/A California 2006-2017 N/A N/A New York 2017 N/A 2017 New Jersey State Tax Reform In July 2018, the State of New Jersey made changes to its income tax laws, including imposing a temporary surtax on allocated corporate taxable income of 2.5% effective January 1, 2018 and 2019 and 1.5% in 2020 and 2021, as well as requiring corporate taxpayers to file in a combined reporting group as defined under New Jersey law starting in 2019. Both provisions include an exemption for public utilities. 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. In 2018, PSEG’s non-utility business recorded $7 million of surtax as a result of these new provisions. This New Jersey tax legislation did not have a material impact on PSEG’s deferred income tax balance.
Power [Member]
Income Taxes [Line Items]
Income Taxes	Income Taxes A reconciliation of reported income tax expense for PSEG with the amount computed by multiplying pre-tax income by the statutory federal income tax rate of 21% in 2018 and 35% in 2017 and 2016 is as follows: Years Ended December 31, PSEG 2018 2017 2016 Millions Net Income $ 1,438 $ 1,574 $ 887 Income Taxes: Operating Income: Current (Benefit) Expense: Federal $ (97 ) $ 86 $ (74 ) State 83 (31 ) 61 Total Current (14 ) 55 (13 ) Deferred Expense (Benefit): Federal 373 (482 ) 311 State 71 92 28 Total Deferred 444 (390 ) 339 Investment Tax Credit (ITC) (13 ) 29 85 Total Income Tax Expense (Benefit) $ 417 $ (306 ) $ 411 Pre-Tax Income $ 1,855 $ 1,268 $ 1,298 Tax Computed at Statutory Rate 21% in 2018 and 35% in 2017 and 2016 $ 390 $ 444 $ 454 Increase (Decrease) Attributable to Flow-Through of Certain Tax Adjustments: State Income Taxes (net of federal income tax) 123 36 56 Uncertain Tax Positions (24 ) (3 ) (31 ) Manufacturing Deduction — (13 ) (17 ) NDT Fund (13 ) 19 3 Plant-Related Items (10 ) (23 ) (20 ) Tax Credits (16 ) (22 ) (25 ) Audit Settlement — 6 — Tax Adjustment Credit (30 ) — — Deferred Tax Expense (Benefit) - Tax Act 3 (755 ) — Other (6 ) 5 (9 ) Sub-Total 27 (750 ) (43 ) Total Income Tax Expense (Benefit) $ 417 $ (306 ) $ 411 Effective Income Tax Rate 22.5 % (24.1 )% 31.7 % The following is an analysis of deferred income taxes for PSEG: As of December 31, PSEG 2018 2017 Millions Deferred Income Taxes Assets: Noncurrent Regulatory Liability Excess Deferred Tax $ 606 $ 602 OPEB 163 217 Related to Uncertain Tax Position 71 142 Total Noncurrent Assets $ 840 $ 961 Liabilities: Noncurrent: Plant-Related Items $ 4,817 $ 4,257 New Jersey Corporate Business Tax 756 674 Leasing Activities 307 384 AROs and NDT Fund 196 233 Pension Costs 111 123 Taxes Recoverable Through Future Rates (net) 89 80 Other 12 171 Total Noncurrent Liabilities $ 6,288 $ 5,922 Summary of Accumulated Deferred Income Taxes: Net Noncurrent Deferred Income Tax Liabilities $ 5,448 $ 4,961 ITC 265 279 Net Total Noncurrent Deferred Income Taxes and ITC $ 5,713 $ 5,240 The deferred tax effect of certain assets and liabilities is presented in the table above net of the deferred tax effect associated with the respective regulatory deferrals. In December 2017, new tax legislation was enacted, reducing the statutory U.S. corporate income tax rate from a maximum of 35% to 21%, effective January 1, 2018. PSEG is subject to ASC 740, which requires that the effect on deferred tax assets and liabilities of a change in tax rates be recognized in the period the tax rate was enacted. A reconciliation of reported income tax expense for PSE&G with the amount computed by multiplying pre-tax income by the statutory federal income tax rate of 21% in 2018 and 35% in 2017 and 2016 is as follows: Years Ended December 31, PSE&G 2018 2017 2016 Millions Net Income $ 1,067 $ 973 $ 889 Income Taxes: Operating Income: Current (Benefit) Expense: Federal $ (62 ) $ (52 ) $ (153 ) State 1 (1 ) 10 Total Current (61 ) (53 ) (143 ) Deferred Expense: Federal 287 492 551 State 122 129 102 Total Deferred 409 621 653 ITC (4 ) (5 ) 5 Total Income Tax Expense $ 344 $ 563 $ 515 Pre-Tax Income $ 1,411 $ 1,536 $ 1,404 Tax Computed at Statutory Rate 21% in 2018 and 35% in 2017 and 2016 $ 296 $ 538 $ 491 Increase (Decrease) Attributable to Flow-Through of Certain Tax Adjustments: State Income Taxes (net of federal income tax) 98 83 72 Uncertain Tax Positions (1 ) (9 ) (18 ) Plant-Related Items (10 ) (23 ) (20 ) Tax Credits (8 ) (9 ) (7 ) Tax Adjustment Credit (30 ) — — Deferred Tax Benefit - Tax Act — (10 ) — Other (1 ) (7 ) (3 ) Sub-Total 48 25 24 Total Income Tax Expense $ 344 $ 563 $ 515 Effective Income Tax Rate 24.4 % 36.7 % 36.7 % The following is an analysis of deferred income taxes for PSE&G: As of December 31, PSE&G 2018 2017 Millions Deferred Income Taxes Assets: Noncurrent: Regulatory Liability Excess Deferred Tax $ 606 $ 602 OPEB 114 116 Total Noncurrent Assets $ 720 $ 718 Liabilities: Noncurrent: Plant-Related Items $ 3,622 $ 3,311 New Jersey Corporate Business Tax 486 378 Pension Costs 159 152 Conservation Costs 36 24 Taxes Recoverable Through Future Rates (net) 89 80 Other 84 86 Total Noncurrent Liabilities $ 4,476 $ 4,031 Summary of Accumulated Deferred Income Taxes: Net Noncurrent Deferred Income Tax Liabilities $ 3,756 $ 3,313 ITC 74 78 Net Total Noncurrent Deferred Income Taxes and ITC $ 3,830 $ 3,391 The deferred tax effect of certain assets and liabilities is presented in the table above net of the deferred tax effect associated with the respective regulatory deferrals. In December 2017, new tax legislation was enacted, reducing the statutory U.S. corporate income tax rate from a maximum of 35% to 21%, effective January 1, 2018. PSE&G is subject to ASC 740, which requires that the effect on deferred tax assets and liabilities of a change in tax rates be recognized in the period the tax rate was enacted. A reconciliation of reported income tax expense for Power with the amount computed by multiplying pre-tax income by the statutory federal income tax rate of 21% in 2018 and 35% in 2017 and 2016 is as follows: Years Ended December 31, Power 2018 2017 2016 Millions Net Income $ 365 $ 479 $ 18 Income Taxes: Operating Income: Current (Benefit) Expense: Federal $ (164 ) $ 95 $ 107 State 24 (17 ) 40 Total Current (140 ) 78 147 Deferred Expense (Benefit): Federal 214 (804 ) (222 ) State 1 (37 ) (68 ) Total Deferred 215 (841 ) (290 ) ITC (9 ) 34 82 Total Income Tax Expense (Benefit) $ 66 $ (729 ) $ (61 ) Pre-Tax Income (Loss) $ 431 $ (250 ) $ (43 ) Tax Computed at Statutory Rate 21% in 2018 and 35% in 2017 and 2016 $ 91 $ (88 ) $ (15 ) Increase (Decrease) Attributable to Flow-Through of Certain Tax Adjustments: State Income Taxes (net of federal income tax) 21 (36 ) (18 ) Manufacturing Deduction — (13 ) (17 ) NDT Fund (13 ) 19 3 Tax Credits (7 ) (12 ) (18 ) Uncertain Tax Positions (24 ) 7 9 Audit Settlement — 1 — Deferred Tax Benefit - Tax Act (1 ) (610 ) — Other (1 ) 3 (5 ) Sub-Total (25 ) (641 ) (46 ) Total Income Tax Expense (Benefit) $ 66 $ (729 ) $ (61 ) Effective Income Tax Rate 15.3 % 291.6 % 141.9 % The following is an analysis of deferred income taxes for Power: As of December 31, Power 2018 2017 Millions Deferred Income Taxes Assets: Noncurrent: Related to Uncertain Tax Positions $ 60 $ 45 Pension Costs 52 40 Contractual Liabilities & Environmental Costs 9 12 Other 98 93 Total Noncurrent Assets $ 219 $ 190 Liabilities: Noncurrent: Plant-Related Items $ 1,189 $ 935 AROs and NDT Fund 197 235 New Jersey Corporate Business Tax 260 225 Total Noncurrent Liabilities $ 1,646 $ 1,395 Summary of Accumulated Deferred Income Taxes: Net Noncurrent Deferred Income Tax Liabilities $ 1,427 $ 1,205 ITC 192 201 Net Total Noncurrent Deferred Income Taxes and ITC $ 1,619 $ 1,406 PSEG, PSE&G and Power each provide deferred taxes at the enacted statutory tax rate for all temporary differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities irrespective of the treatment for rate-making purposes. Management believes that it is probable that the accumulated tax benefits that previously have been treated as a flow-through item to PSE&G customers will be recovered from or refunded to PSE&G’s customers in the future. See Note 7. Regulatory Assets and Liabilities . In December 2017, the U.S. government enacted comprehensive tax legislation. The Tax Act establishes new tax laws that took effect in 2018, including, but not limited to (1) reduction of the U.S. federal corporate tax rate from a maximum of 35% to 21%; (2) elimination of the corporate alternative minimum tax (AMT); (3) a new limitation on deductible interest expense; (4) the repeal of the manufacturing deduction; (5) limitations on the deductibility of certain executive compensation; and (6) limitations on net operating losses (NOLs) generated after December 31, 2017, to 80% of taxable income with an indefinite carryforward period. In addition, certain changes were made to the bonus depreciation rules that impacted 2017. In 2018 and beyond, it is expected that Power will be entitled to 100% expensing and bonus depreciation will no longer apply to PSE&G. As required under ASC 740, the ending 2017 deferred tax balances were adjusted to reflect the enacted lower tax rate, which resulted in a deferred tax benefit of $755 million , including $610 million related to Power and $149 million related to Energy Holdings (including other impacts related to the new tax legislation, PSEG’s net non-cash provisional earnings benefit was $745 million , including $588 million related to Power and $147 million related to Energy Holdings). There were no further material deferred tax benefits recorded in 2018 as a result of the Tax Act. In addition, PSE&G had excess deferred taxes of approximately $2.1 billion as of December 31, 2017 and recorded a $2.9 billion revenue impact of these excess deferred taxes as Regulatory Liabilities. In 2018, PSE&G recorded an additional $34 million of excess deferred taxes and a $46 million revenue impact of these excess taxes as Regulatory Liabilities associated with the 2017 return to accrual. PSEG, PSE&G and Power completed their accounting for the Tax Act based on the current regulatory guidance available at the end of the Staff Accounting Bulletin No. 118 measurement period, not to extend beyond one year from the enactment date of the Tax Act. The Tax Act has led to lower customer rates due to lower income tax expense recoveries and the BPU and FERC have approved our proposals to refund excess deferred income tax Regulatory Liabilities. See Note 7. Regulatory Assets and Liabilities for additional information. 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. 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. Further, in November 2018 the IRS issued Proposed Regulations addressing the interest disallowance rules contained in the Tax Act. For non-regulated businesses, these rules set a cap on the amount of interest that can be deducted in a given year. Any amount that is disallowed can be carried forward indefinitely. For 2018, PSEG and Power expect that a portion of the interest will be disallowed in the current period but realized in future periods. As a result, PSEG and Power recorded a deferred tax asset of $54 million and $8 million , respectively, in 2018. However, certain aspects of the proposed regulations are unclear; therefore, PSEG recorded taxes based on its interpretation of the relevant statute. Depreciation amounts recorded in 2018 were based on PSEG’s interpretation of the Tax Act and the depreciation rules contained in the Notice. Such amounts are subject to change based on several factors, including but not limited to, the IRS and state taxing authorities issuing final guidance and/or further clarification. Any further guidance or clarification could impact PSEG’s, PSE&G’s and Power’s financial statements. The Protecting Americans from Tax Hikes Act of 2015 (2015 Tax Act), among other provisions, included an extension of the bonus depreciation rules and the 30% investment tax credit for qualified property placed into service after 2016. Qualified property that is placed into service from January 1, 2015 through December 31, 2017 is eligible for the 50% bonus depreciation. The provisions of the 2015 Tax Act have generated significant cash tax benefits for PSEG, PSE&G and Power through tax benefits related to the accelerated depreciation. For the period beginning September 28, 2017, subject to the transition rules, the Tax Act has modified the bonus depreciation rules of the 2015 Tax Act. In 2018, Power generated a $14 million consolidated federal income tax NOL and PSE&G generated a $21 million New Jersey Corporate Business tax NOL. Both PSE&G and Power expect to fully realize their respective NOLs. There are no other material tax carryforwards in other jurisdictions. PSEG recorded the following amounts related to its unrecognized tax benefits, which were primarily comprised of amounts recorded for PSE&G, Power and Energy Holdings: 2018 PSEG PSE&G Power Energy Holdings Millions Total Amount of Unrecognized Tax Benefits as of January 1, 2018 $ 334 $ 135 $ 142 $ 53 Increases as a Result of Positions Taken in a Prior Period 11 4 4 3 Decreases as a Result of Positions Taken in a Prior Period (70 ) (31 ) (37 ) (2 ) Increases as a Result of Positions Taken during the Current Period 52 3 48 — Decreases as a Result of Positions Taken during the Current Period (3 ) (3 ) — — Decreases as a Result of Settlements with Taxing Authorities (6 ) — (6 ) — Decreases due to Lapses of Applicable Statute of Limitations — — — — Total Amount of Unrecognized Tax Benefits as of December 31, 2018 $ 318 $ 108 $ 151 $ 54 Accumulated Deferred Income Taxes Associated with Unrecognized Tax Benefits (173 ) (57 ) (104 ) (12 ) Regulatory Asset—Unrecognized Tax Benefits (46 ) (46 ) — — Total Amount of Unrecognized Tax Benefits that if Recognized, would Impact the Effective Tax Rate (including Interest and Penalties) $ 99 $ 5 $ 47 $ 42 2017 PSEG PSE&G Power Energy Holdings Millions Total Amount of Unrecognized Tax Benefits as of January 1, 2017 $ 328 $ 140 $ 128 $ 57 Increases as a Result of Positions Taken in a Prior Period 40 15 18 8 Decreases as a Result of Positions Taken in a Prior Period (32 ) (11 ) (10 ) (13 ) Increases as a Result of Positions Taken during the Current Period 12 5 6 1 Decreases as a Result of Positions Taken during the Current Period (1 ) (1 ) — — Decreases as a Result of Settlements with Taxing Authorities — — — — Decreases due to Lapses of Applicable Statute of Limitations (13 ) (13 ) — — Total Amount of Unrecognized Tax Benefits as of December 31, 2017 $ 334 $ 135 $ 142 $ 53 Accumulated Deferred Income Taxes Associated with Unrecognized Tax Benefits (157 ) (73 ) (72 ) (12 ) Regulatory Asset—Unrecognized Tax Benefits (56 ) (56 ) — — Total Amount of Unrecognized Tax Benefits that if Recognized, would Impact the Effective Tax Rate (including Interest and Penalties) $ 121 $ 6 $ 70 $ 41 2016 PSEG PSE&G Power Energy Holdings Millions Total Amount of Unrecognized Tax Benefits as of January 1, 2016 $ 386 $ 181 $ 111 $ 93 Increases as a Result of Positions Taken in a Prior Period 12 3 6 2 Decreases as a Result of Positions Taken in a Prior Period (62 ) (23 ) (1 ) (38 ) Increases as a Result of Positions Taken during the Current Period 19 6 12 — Decreases as a Result of Positions Taken during the Current Period — — — — Decreases as a Result of Settlements with Taxing Authorities — — — — Decreases due to Lapses of Applicable Statute of Limitations (27 ) (27 ) — — Total Amount of Unrecognized Tax Benefits as of December 31, 2016 $ 328 $ 140 $ 128 $ 57 Accumulated Deferred Income Taxes Associated with Unrecognized Tax Benefits (200 ) (106 ) (74 ) (20 ) Regulatory Asset—Unrecognized Tax Benefits (31 ) (31 ) — — Total Amount of Unrecognized Tax Benefits that if Recognized, would Impact the Effective Tax Rate (including Interest and Penalties) $ 97 $ 3 $ 54 $ 37 PSEG and its subsidiaries include accrued interest and penalties related to uncertain tax positions required to be recorded, as Income Tax Expense in the Consolidated Statements of Operations. Accumulated interest and penalties that are recorded on the Consolidated Balance Sheets on uncertain tax positions were as follows: Accumulated Interest and Penalties on Uncertain Tax Positions as of December 31, 2018 2017 2016 Millions PSE&G $ 12 $ 25 $ 22 Power 9 24 17 Energy Holdings 22 21 20 Total $ 43 $ 70 $ 59 It is reasonably possible that total unrecognized tax benefits will significantly increase or decrease within the next twelve months due to either agreements with various taxing authorities upon audit, the expiration of the Statute of Limitations, or other pending tax matters. These potential increases or decreases are as follows: Possible (Increase)/Decrease in Total Unrecognized Tax Benefits Over the next 12 Months Millions PSEG $ 112 PSE&G $ 62 Power $ 34 A description of income tax years that remain subject to examination by material jurisdictions, where an examination has not already concluded are: PSEG PSE&G Power United States Federal 2011-2017 N/A N/A New Jersey 2006-2017 2011-2017 N/A Pennsylvania 2015-2017 2015-2017 N/A Connecticut 2016-2017 N/A N/A California 2006-2017 N/A N/A New York 2017 N/A 2017 New Jersey State Tax Reform In July 2018, the State of New Jersey made changes to its income tax laws, including imposing a temporary surtax on allocated corporate taxable income of 2.5% effective January 1, 2018 and 2019 and 1.5% in 2020 and 2021, as well as requiring corporate taxpayers to file in a combined reporting group as defined under New Jersey law starting in 2019. Both provisions include an exemption for public utilities. 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. In 2018, PSEG’s non-utility business recorded $7 million of surtax as a result of these new provisions. This New Jersey tax legislation did not have a material impact on PSEG’s deferred income tax balance.

Accumulated Other Comprehensive

Accumulated Other Comprehensive Income (Loss), Net of Tax Accumulated Other Comprehensive Income (Loss), Net of Tax	12 Months Ended
	Dec. 31, 2018
Accumulated Other Comprehensive Income (Loss) [Line Items]
Accumulated Other Comprehensive Income (Loss), Net of Tax	Accumulated Other Comprehensive Income (Loss), Net of Tax PSEG Other Comprehensive Income (Loss) Accumulated Other Comprehensive Income (Loss) Cash Flow Hedges Pension and OPEB Plans Available-for -Sale Securities Total Millions Balance as of December 31, 2015 $ — $ (386 ) $ 91 $ (295 ) Other Comprehensive Income before Reclassifications 2 (45 ) 40 (3 ) Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) — 33 2 35 Net Current Period Other Comprehensive Income (Loss) 2 (12 ) 42 32 Balance as of December 31, 2016 $ 2 $ (398 ) $ 133 $ (263 ) Other Comprehensive Income before Reclassifications — (32 ) 109 77 Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) (2 ) 24 (65 ) (43 ) Net Current Period Other Comprehensive Income (Loss) (2 ) (8 ) 44 34 Balance as of December 31, 2017 $ — $ (406 ) $ 177 $ (229 ) Cumulative Effect Adjustment to Reclassify Unrealized Net Gains on Equity Investments to Retained Earnings — — (176 ) (176 ) Current Period Other Comprehensive Income (Loss) Other Comprehensive Income before Reclassifications (1 ) 17 (25 ) (9 ) Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) — 29 8 37 Net Current Period Other Comprehensive Income (Loss) (1 ) 46 (17 ) 28 Net Change in Accumulated Other Comprehensive Income (Loss) (1 ) 46 (193 ) (148 ) Balance as of December 31, 2018 $ (1 ) $ (360 ) $ (16 ) $ (377 ) Power Other Comprehensive Income (Loss) Accumulated Other Comprehensive Income (Loss) Cash Flow Hedges Pension and OPEB Plans Available-for -Sale Securities Total Millions Balance as of December 31, 2015 $ — $ (327 ) $ 87 $ (240 ) Other Comprehensive Income before Reclassifications — (42 ) 39 (3 ) Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) — 29 3 32 Net Current Period Other Comprehensive Income (Loss) — (13 ) 42 29 Balance as of December 31, 2016 $ — $ (340 ) $ 129 $ (211 ) Other Comprehensive Income before Reclassifications — (28 ) 106 78 Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) — 21 (60 ) (39 ) Net Current Period Other Comprehensive Income (Loss) — (7 ) 46 39 Balance as of December 31, 2017 $ — $ (347 ) $ 175 $ (172 ) Cumulative Effect Adjustment to Reclassify Unrealized Net Gains on Equity Investments to Retained Earnings — — (175 ) (175 ) Current Period Other Comprehensive Income (Loss) Other Comprehensive Income before Reclassifications — 16 (19 ) (3 ) Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) — 25 6 31 Net Current Period Other Comprehensive Income (Loss) — 41 (13 ) 28 Net Change in Accumulated Other Comprehensive Income (Loss) — 41 (188 ) (147 ) Balance as of December 31, 2018 $ — $ (306 ) $ (13 ) $ (319 ) PSEG Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement Year Ended December 31, 2016 Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) Location of Pre-Tax Amount In Statement of Operations Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount Millions Pension and OPEB Plans Amortization of Prior Service (Cost) Credit Non-Operating Pension and OPEB Credits (Costs) $ 12 $ (5 ) $ 7 Amortization of Actuarial Loss Non-Operating Pension and OPEB Credits (Costs) (68 ) 28 (40 ) Total Pension and OPEB Plans (56 ) 23 (33 ) Available-for-Sale Securities Realized Gains (Losses) and Other-Than-Temporary Impairments (OTTI) Net Gains (Losses) on Trust Investments (6 ) 4 (2 ) Total Available-for-Sale Securities (6 ) 4 (2 ) Total $ (62 ) $ 27 $ (35 ) Power Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement Year Ended December 31, 2016 Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) Location of Pre-Tax Amount In Statement of Operations Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount Millions Pension and OPEB Plans Amortization of Prior Service (Cost) Credit Non-Operating Pension and OPEB Credits (Costs) $ 11 $ (5 ) $ 6 Amortization of Actuarial Loss Non-Operating Pension and OPEB Credits (Costs) (59 ) 24 (35 ) Total Pension and OPEB Plans (48 ) 19 (29 ) Available-for-Sale Securities Realized Gains (Losses) and OTTI Net Gains (Losses) on Trust Investments (6 ) 3 (3 ) Total Available-for-Sale Securities (6 ) 3 (3 ) Total $ (54 ) $ 22 $ (32 ) PSEG Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement Year Ended December 31, 2017 Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) Location of Pre-Tax Amount In Statement of Operations Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount Millions Cash Flow Hedges Interest Rate Swaps Interest Expense $ 3 $ (1 ) $ 2 Total Cash Flow Hedges 3 (1 ) 2 Pension and OPEB Plans Amortization of Prior Service (Cost) Credit Non-Operating Pension and OPEB Credits (Costs) 10 (4 ) 6 Amortization of Actuarial Loss Non-Operating Pension and OPEB Credits (Costs) (51 ) 21 (30 ) Total Pension and OPEB Plans (41 ) 17 (24 ) Available-for-Sale Securities Realized Gains (Losses) and OTTI Net Gains (Losses) on Trust Investments 134 (69 ) 65 Total Available-for-Sale Securities 134 (69 ) 65 Total $ 96 $ (53 ) $ 43 Power Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement Year Ended December 31, 2017 Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) Location of Pre-Tax Amount In Statement of Operations Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount Millions Pension and OPEB Plans Amortization of Prior Service (Cost) Credit Non-Operating Pension and OPEB Credits (Costs) $ 9 $ (4 ) $ 5 Amortization of Actuarial Loss Non-Operating Pension and OPEB Credits (Costs) (44 ) 18 (26 ) Total Pension and OPEB Plans (35 ) 14 (21 ) Available-for-Sale Securities Realized Gains (Losses) and OTTI Net Gains (Losses) on Trust Investments 125 (65 ) 60 Total Available-for-Sale Securities 125 (65 ) 60 Total $ 90 $ (51 ) $ 39 PSEG Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement Year Ended December 31, 2018 Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) Location of Pre-Tax Amount In Statement of Operations Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount Millions Pension and OPEB Plans Amortization of Prior Service (Cost) Credit Non-Operating Pension and OPEB Credits (Costs) $ 6 $ (2 ) $ 4 Amortization of Actuarial Loss Non-Operating Pension and OPEB Credits (Costs) (47 ) 14 (33 ) Total Pension and OPEB Plans (41 ) 12 (29 ) Available-for-Sale Securities Realized Gains (Losses) and OTTI Net Gains (Losses) on Trust Investments (13 ) 5 (8 ) Total Available-for-Sale Securities (13 ) 5 (8 ) Total $ (54 ) $ 17 $ (37 ) Power Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement Year Ended December 31, 2018 Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) Location of Pre-Tax Amount In Statement of Operations Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount Millions Pension and OPEB Plans Amortization of Prior Service (Cost) Credit Non-Operating Pension and OPEB Credits (Costs) $ 5 $ (1 ) $ 4 Amortization of Actuarial Loss Non-Operating Pension and OPEB Credits (Costs) (40 ) 11 (29 ) Total Pension and OPEB Plans (35 ) 10 (25 ) Available-for-Sale Securities Realized Gains (Losses) and OTTI Net Gains (Losses) on Trust Investments (11 ) 5 (6 ) Total Available-for-Sale Securities (11 ) 5 (6 ) Total $ (46 ) $ 15 $ (31 )
Power [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Accumulated Other Comprehensive Income (Loss), Net of Tax	Accumulated Other Comprehensive Income (Loss), Net of Tax PSEG Other Comprehensive Income (Loss) Accumulated Other Comprehensive Income (Loss) Cash Flow Hedges Pension and OPEB Plans Available-for -Sale Securities Total Millions Balance as of December 31, 2015 $ — $ (386 ) $ 91 $ (295 ) Other Comprehensive Income before Reclassifications 2 (45 ) 40 (3 ) Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) — 33 2 35 Net Current Period Other Comprehensive Income (Loss) 2 (12 ) 42 32 Balance as of December 31, 2016 $ 2 $ (398 ) $ 133 $ (263 ) Other Comprehensive Income before Reclassifications — (32 ) 109 77 Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) (2 ) 24 (65 ) (43 ) Net Current Period Other Comprehensive Income (Loss) (2 ) (8 ) 44 34 Balance as of December 31, 2017 $ — $ (406 ) $ 177 $ (229 ) Cumulative Effect Adjustment to Reclassify Unrealized Net Gains on Equity Investments to Retained Earnings — — (176 ) (176 ) Current Period Other Comprehensive Income (Loss) Other Comprehensive Income before Reclassifications (1 ) 17 (25 ) (9 ) Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) — 29 8 37 Net Current Period Other Comprehensive Income (Loss) (1 ) 46 (17 ) 28 Net Change in Accumulated Other Comprehensive Income (Loss) (1 ) 46 (193 ) (148 ) Balance as of December 31, 2018 $ (1 ) $ (360 ) $ (16 ) $ (377 ) Power Other Comprehensive Income (Loss) Accumulated Other Comprehensive Income (Loss) Cash Flow Hedges Pension and OPEB Plans Available-for -Sale Securities Total Millions Balance as of December 31, 2015 $ — $ (327 ) $ 87 $ (240 ) Other Comprehensive Income before Reclassifications — (42 ) 39 (3 ) Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) — 29 3 32 Net Current Period Other Comprehensive Income (Loss) — (13 ) 42 29 Balance as of December 31, 2016 $ — $ (340 ) $ 129 $ (211 ) Other Comprehensive Income before Reclassifications — (28 ) 106 78 Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) — 21 (60 ) (39 ) Net Current Period Other Comprehensive Income (Loss) — (7 ) 46 39 Balance as of December 31, 2017 $ — $ (347 ) $ 175 $ (172 ) Cumulative Effect Adjustment to Reclassify Unrealized Net Gains on Equity Investments to Retained Earnings — — (175 ) (175 ) Current Period Other Comprehensive Income (Loss) Other Comprehensive Income before Reclassifications — 16 (19 ) (3 ) Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) — 25 6 31 Net Current Period Other Comprehensive Income (Loss) — 41 (13 ) 28 Net Change in Accumulated Other Comprehensive Income (Loss) — 41 (188 ) (147 ) Balance as of December 31, 2018 $ — $ (306 ) $ (13 ) $ (319 ) PSEG Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement Year Ended December 31, 2016 Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) Location of Pre-Tax Amount In Statement of Operations Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount Millions Pension and OPEB Plans Amortization of Prior Service (Cost) Credit Non-Operating Pension and OPEB Credits (Costs) $ 12 $ (5 ) $ 7 Amortization of Actuarial Loss Non-Operating Pension and OPEB Credits (Costs) (68 ) 28 (40 ) Total Pension and OPEB Plans (56 ) 23 (33 ) Available-for-Sale Securities Realized Gains (Losses) and Other-Than-Temporary Impairments (OTTI) Net Gains (Losses) on Trust Investments (6 ) 4 (2 ) Total Available-for-Sale Securities (6 ) 4 (2 ) Total $ (62 ) $ 27 $ (35 ) Power Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement Year Ended December 31, 2016 Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) Location of Pre-Tax Amount In Statement of Operations Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount Millions Pension and OPEB Plans Amortization of Prior Service (Cost) Credit Non-Operating Pension and OPEB Credits (Costs) $ 11 $ (5 ) $ 6 Amortization of Actuarial Loss Non-Operating Pension and OPEB Credits (Costs) (59 ) 24 (35 ) Total Pension and OPEB Plans (48 ) 19 (29 ) Available-for-Sale Securities Realized Gains (Losses) and OTTI Net Gains (Losses) on Trust Investments (6 ) 3 (3 ) Total Available-for-Sale Securities (6 ) 3 (3 ) Total $ (54 ) $ 22 $ (32 ) PSEG Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement Year Ended December 31, 2017 Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) Location of Pre-Tax Amount In Statement of Operations Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount Millions Cash Flow Hedges Interest Rate Swaps Interest Expense $ 3 $ (1 ) $ 2 Total Cash Flow Hedges 3 (1 ) 2 Pension and OPEB Plans Amortization of Prior Service (Cost) Credit Non-Operating Pension and OPEB Credits (Costs) 10 (4 ) 6 Amortization of Actuarial Loss Non-Operating Pension and OPEB Credits (Costs) (51 ) 21 (30 ) Total Pension and OPEB Plans (41 ) 17 (24 ) Available-for-Sale Securities Realized Gains (Losses) and OTTI Net Gains (Losses) on Trust Investments 134 (69 ) 65 Total Available-for-Sale Securities 134 (69 ) 65 Total $ 96 $ (53 ) $ 43 Power Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement Year Ended December 31, 2017 Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) Location of Pre-Tax Amount In Statement of Operations Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount Millions Pension and OPEB Plans Amortization of Prior Service (Cost) Credit Non-Operating Pension and OPEB Credits (Costs) $ 9 $ (4 ) $ 5 Amortization of Actuarial Loss Non-Operating Pension and OPEB Credits (Costs) (44 ) 18 (26 ) Total Pension and OPEB Plans (35 ) 14 (21 ) Available-for-Sale Securities Realized Gains (Losses) and OTTI Net Gains (Losses) on Trust Investments 125 (65 ) 60 Total Available-for-Sale Securities 125 (65 ) 60 Total $ 90 $ (51 ) $ 39 PSEG Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement Year Ended December 31, 2018 Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) Location of Pre-Tax Amount In Statement of Operations Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount Millions Pension and OPEB Plans Amortization of Prior Service (Cost) Credit Non-Operating Pension and OPEB Credits (Costs) $ 6 $ (2 ) $ 4 Amortization of Actuarial Loss Non-Operating Pension and OPEB Credits (Costs) (47 ) 14 (33 ) Total Pension and OPEB Plans (41 ) 12 (29 ) Available-for-Sale Securities Realized Gains (Losses) and OTTI Net Gains (Losses) on Trust Investments (13 ) 5 (8 ) Total Available-for-Sale Securities (13 ) 5 (8 ) Total $ (54 ) $ 17 $ (37 ) Power Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement Year Ended December 31, 2018 Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) Location of Pre-Tax Amount In Statement of Operations Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount Millions Pension and OPEB Plans Amortization of Prior Service (Cost) Credit Non-Operating Pension and OPEB Credits (Costs) $ 5 $ (1 ) $ 4 Amortization of Actuarial Loss Non-Operating Pension and OPEB Credits (Costs) (40 ) 11 (29 ) Total Pension and OPEB Plans (35 ) 10 (25 ) Available-for-Sale Securities Realized Gains (Losses) and OTTI Net Gains (Losses) on Trust Investments (11 ) 5 (6 ) Total Available-for-Sale Securities (11 ) 5 (6 ) Total $ (46 ) $ 15 $ (31 )

Earnings Per Share (EPS) and Di

Earnings Per Share (EPS) and Dividends	12 Months Ended
	Dec. 31, 2018
Earnings Per Share [Abstract]
Earnings Per Share (EPS) and Dividends	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. For additional information on PSEG’s stock compensation plans see Note 19. Stock Based Compensation . 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: Years Ended December 31, 2018 2017 2016 Basic Diluted Basic Diluted Basic Diluted EPS Numerator: (Millions) Net Income $ 1,438 $ 1,438 $ 1,574 $ 1,574 $ 887 $ 887 EPS Denominator: (Millions) Weighted Average Common Shares Outstanding 504 504 505 505 505 505 Effect of Stock Based Compensation Awards — 3 — 2 — 3 Total Shares 504 507 505 507 505 508 EPS: Net Income $ 2.85 $ 2.83 $ 3.12 $ 3.10 $ 1.76 $ 1.75 There were approximately 0.4 million stock options excluded from the weighted average common shares used for diluted EPS due to their antidilutive effect for the year ended December 31, 2016 . For additional information on all the types of long-term incentive awards, see Note 19. Stock Based Compensation . Dividends Years Ended December 31, Dividend Payments on Common Stock 2018 2017 2016 Per Share $ 1.80 $ 1.72 $ 1.64 in Millions $ 910 $ 870 $ 830 On February 19, 2019 , PSEG’s Board of Directors approved a $0.47 per share common stock dividend for the first quarter of 2019 .

Financial Information By Busine

Financial Information By Business Segments	12 Months Ended
	Dec. 31, 2018
Segment Reporting Information [Line Items]
Financial Information By Business Segments	Financial Information by Business Segment Basis of Organization PSEG’s, PSE&G’s and Power’s operating segments were determined by management in accordance with GAAP. These segments were determined based on how management measures performance based on segment Net Income, as illustrated in the following table, and how resources are allocated to each business. PSEG’s reportable segments are PSE&G and Power. PSE&G and Power each represent a single reportable segment and therefore no separate segment information is provided for these Registrants. PSE&G PSE&G earns revenues from its tariffs, under which it provides electric transmission and electric and gas distribution services to residential, commercial and industrial customers in New Jersey. The rates charged for electric transmission are regulated by FERC while the rates charged for electric and gas distribution are regulated by the BPU. Revenues are also earned from several other activities such as solar investments, sundry sales, the appliance service business, wholesale transmission services and other miscellaneous services. Power Power earns revenues by selling energy, capacity and ancillary services on a wholesale basis under contract to power marketers and to load-serving entities and by bidding energy, capacity and ancillary services into the markets for these products. A significant portion of Power’s revenue is obtained from the various ISOs in which Power operates. The ISOs act similarly to a clearing house for all of its members in that all revenues paid out are collected from market participants based on their consumption of energy and energy-related products. Power also enters into bilateral contracts for energy, capacity, FTRs, gas, emission allowances and other energy-related contracts to optimize the value of its portfolio of generating assets and its electric and gas supply obligations. Other This category includes amounts applicable to Energy Holdings and PSEG LI, which are below the quantitative threshold for separate disclosure as reportable segments. Other also includes amounts applicable to PSEG (parent corporation) and Services. PSE&G Power Other (A) Eliminations (B) Consolidated Total Millions Year Ended December 31, 2018 Operating Revenues $ 6,471 $ 4,146 $ 571 $ (1,492 ) $ 9,696 Depreciation and Amortization 770 354 34 — 1,158 Operating Income (Loss) 1,606 596 96 — 2,298 Income from Equity Method Investments — 15 — — 15 Interest Income 21 5 9 (6 ) 29 Interest Expense 333 76 73 (6 ) 476 Income (Loss) before Income Taxes 1,411 431 13 — 1,855 Income Tax Expense (Benefit) 344 66 7 — 417 Net Income (Loss) $ 1,067 $ 365 $ 6 $ — $ 1,438 Gross Additions to Long-Lived Assets $ 2,896 $ 996 $ 20 $ — $ 3,912 As of December 31, 2018 Total Assets $ 31,109 $ 12,594 $ 2,604 $ (981 ) $ 45,326 Investments in Equity Method Subsidiaries $ — $ 86 $ — $ — $ 86 PSE&G Power Other (A) Eliminations (B) Consolidated Total Millions Year Ended December 31, 2017 Operating Revenues $ 6,324 $ 3,860 $ 466 $ (1,556 ) $ 9,094 Depreciation and Amortization 685 1,268 33 — 1,986 Operating Income (Loss) 1,760 (367 ) 36 — 1,429 Income from Equity Method Investments — 14 — — 14 Interest Income 24 3 5 (2 ) 30 Interest Expense 303 50 40 (2 ) 391 Income (Loss) before Income Taxes 1,536 (250 ) (18 ) — 1,268 Income Tax Expense (Benefit) 563 (729 ) (140 ) — (306 ) Net Income (Loss) $ 973 $ 479 $ 122 $ — $ 1,574 Gross Additions to Long-Lived Assets $ 2,919 $ 1,231 $ 40 $ — $ 4,190 As of December 31, 2017 Total Assets $ 28,554 $ 12,418 $ 2,666 $ (922 ) $ 42,716 Investments in Equity Method Subsidiaries $ — $ 87 $ — $ — $ 87 PSE&G Power Other (A) Eliminations (B) Consolidated Total Millions Year Ended December 31, 2016 Operating Revenues $ 6,303 $ 3,861 $ 370 $ (1,568 ) $ 8,966 Depreciation and Amortization 565 881 30 — 1,476 Operating Income (Loss) 1,629 17 (48 ) — 1,598 Income from Equity Method Investments — 11 — — 11 Interest Income 24 4 4 (2 ) 30 Interest Expense 289 84 14 (2 ) 385 Income (Loss) before Income Taxes 1,404 (43 ) (63 ) — 1,298 Income Tax Expense (Benefit) 515 (61 ) (43 ) — 411 Net Income (Loss) $ 889 $ 18 $ (20 ) $ — $ 887 Gross Additions to Long-Lived Assets $ 2,816 $ 1,343 $ 40 $ — $ 4,199 As of December 31, 2016 Total Assets $ 26,288 $ 12,193 $ 2,373 $ (784 ) $ 40,070 Investments in Equity Method Subsidiaries $ — $ 102 $ — $ — $ 102 (A) Includes amounts applicable to Energy Holdings and PSEG LI, which are below the quantitative threshold for separate disclosure as reportable segments. Other also includes amounts applicable to PSEG (parent corporation) and Services. (B) Intercompany eliminations primarily relate to intercompany transactions between PSE&G and Power. For a further discussion of the intercompany transactions between PSE&G and Power, see Note 25. Related-Party Transactions .
PSE&G [Member]
Segment Reporting Information [Line Items]
Financial Information By Business Segments	Financial Information by Business Segment Basis of Organization PSEG’s, PSE&G’s and Power’s operating segments were determined by management in accordance with GAAP. These segments were determined based on how management measures performance based on segment Net Income, as illustrated in the following table, and how resources are allocated to each business. PSEG’s reportable segments are PSE&G and Power. PSE&G and Power each represent a single reportable segment and therefore no separate segment information is provided for these Registrants. PSE&G PSE&G earns revenues from its tariffs, under which it provides electric transmission and electric and gas distribution services to residential, commercial and industrial customers in New Jersey. The rates charged for electric transmission are regulated by FERC while the rates charged for electric and gas distribution are regulated by the BPU. Revenues are also earned from several other activities such as solar investments, sundry sales, the appliance service business, wholesale transmission services and other miscellaneous services. Power Power earns revenues by selling energy, capacity and ancillary services on a wholesale basis under contract to power marketers and to load-serving entities and by bidding energy, capacity and ancillary services into the markets for these products. A significant portion of Power’s revenue is obtained from the various ISOs in which Power operates. The ISOs act similarly to a clearing house for all of its members in that all revenues paid out are collected from market participants based on their consumption of energy and energy-related products. Power also enters into bilateral contracts for energy, capacity, FTRs, gas, emission allowances and other energy-related contracts to optimize the value of its portfolio of generating assets and its electric and gas supply obligations. Other This category includes amounts applicable to Energy Holdings and PSEG LI, which are below the quantitative threshold for separate disclosure as reportable segments. Other also includes amounts applicable to PSEG (parent corporation) and Services. PSE&G Power Other (A) Eliminations (B) Consolidated Total Millions Year Ended December 31, 2018 Operating Revenues $ 6,471 $ 4,146 $ 571 $ (1,492 ) $ 9,696 Depreciation and Amortization 770 354 34 — 1,158 Operating Income (Loss) 1,606 596 96 — 2,298 Income from Equity Method Investments — 15 — — 15 Interest Income 21 5 9 (6 ) 29 Interest Expense 333 76 73 (6 ) 476 Income (Loss) before Income Taxes 1,411 431 13 — 1,855 Income Tax Expense (Benefit) 344 66 7 — 417 Net Income (Loss) $ 1,067 $ 365 $ 6 $ — $ 1,438 Gross Additions to Long-Lived Assets $ 2,896 $ 996 $ 20 $ — $ 3,912 As of December 31, 2018 Total Assets $ 31,109 $ 12,594 $ 2,604 $ (981 ) $ 45,326 Investments in Equity Method Subsidiaries $ — $ 86 $ — $ — $ 86 PSE&G Power Other (A) Eliminations (B) Consolidated Total Millions Year Ended December 31, 2017 Operating Revenues $ 6,324 $ 3,860 $ 466 $ (1,556 ) $ 9,094 Depreciation and Amortization 685 1,268 33 — 1,986 Operating Income (Loss) 1,760 (367 ) 36 — 1,429 Income from Equity Method Investments — 14 — — 14 Interest Income 24 3 5 (2 ) 30 Interest Expense 303 50 40 (2 ) 391 Income (Loss) before Income Taxes 1,536 (250 ) (18 ) — 1,268 Income Tax Expense (Benefit) 563 (729 ) (140 ) — (306 ) Net Income (Loss) $ 973 $ 479 $ 122 $ — $ 1,574 Gross Additions to Long-Lived Assets $ 2,919 $ 1,231 $ 40 $ — $ 4,190 As of December 31, 2017 Total Assets $ 28,554 $ 12,418 $ 2,666 $ (922 ) $ 42,716 Investments in Equity Method Subsidiaries $ — $ 87 $ — $ — $ 87 PSE&G Power Other (A) Eliminations (B) Consolidated Total Millions Year Ended December 31, 2016 Operating Revenues $ 6,303 $ 3,861 $ 370 $ (1,568 ) $ 8,966 Depreciation and Amortization 565 881 30 — 1,476 Operating Income (Loss) 1,629 17 (48 ) — 1,598 Income from Equity Method Investments — 11 — — 11 Interest Income 24 4 4 (2 ) 30 Interest Expense 289 84 14 (2 ) 385 Income (Loss) before Income Taxes 1,404 (43 ) (63 ) — 1,298 Income Tax Expense (Benefit) 515 (61 ) (43 ) — 411 Net Income (Loss) $ 889 $ 18 $ (20 ) $ — $ 887 Gross Additions to Long-Lived Assets $ 2,816 $ 1,343 $ 40 $ — $ 4,199 As of December 31, 2016 Total Assets $ 26,288 $ 12,193 $ 2,373 $ (784 ) $ 40,070 Investments in Equity Method Subsidiaries $ — $ 102 $ — $ — $ 102 (A) Includes amounts applicable to Energy Holdings and PSEG LI, which are below the quantitative threshold for separate disclosure as reportable segments. Other also includes amounts applicable to PSEG (parent corporation) and Services. (B) Intercompany eliminations primarily relate to intercompany transactions between PSE&G and Power. For a further discussion of the intercompany transactions between PSE&G and Power, see Note 25. Related-Party Transactions .
Power [Member]
Segment Reporting Information [Line Items]
Financial Information By Business Segments	Financial Information by Business Segment Basis of Organization PSEG’s, PSE&G’s and Power’s operating segments were determined by management in accordance with GAAP. These segments were determined based on how management measures performance based on segment Net Income, as illustrated in the following table, and how resources are allocated to each business. PSEG’s reportable segments are PSE&G and Power. PSE&G and Power each represent a single reportable segment and therefore no separate segment information is provided for these Registrants. PSE&G PSE&G earns revenues from its tariffs, under which it provides electric transmission and electric and gas distribution services to residential, commercial and industrial customers in New Jersey. The rates charged for electric transmission are regulated by FERC while the rates charged for electric and gas distribution are regulated by the BPU. Revenues are also earned from several other activities such as solar investments, sundry sales, the appliance service business, wholesale transmission services and other miscellaneous services. Power Power earns revenues by selling energy, capacity and ancillary services on a wholesale basis under contract to power marketers and to load-serving entities and by bidding energy, capacity and ancillary services into the markets for these products. A significant portion of Power’s revenue is obtained from the various ISOs in which Power operates. The ISOs act similarly to a clearing house for all of its members in that all revenues paid out are collected from market participants based on their consumption of energy and energy-related products. Power also enters into bilateral contracts for energy, capacity, FTRs, gas, emission allowances and other energy-related contracts to optimize the value of its portfolio of generating assets and its electric and gas supply obligations. Other This category includes amounts applicable to Energy Holdings and PSEG LI, which are below the quantitative threshold for separate disclosure as reportable segments. Other also includes amounts applicable to PSEG (parent corporation) and Services. PSE&G Power Other (A) Eliminations (B) Consolidated Total Millions Year Ended December 31, 2018 Operating Revenues $ 6,471 $ 4,146 $ 571 $ (1,492 ) $ 9,696 Depreciation and Amortization 770 354 34 — 1,158 Operating Income (Loss) 1,606 596 96 — 2,298 Income from Equity Method Investments — 15 — — 15 Interest Income 21 5 9 (6 ) 29 Interest Expense 333 76 73 (6 ) 476 Income (Loss) before Income Taxes 1,411 431 13 — 1,855 Income Tax Expense (Benefit) 344 66 7 — 417 Net Income (Loss) $ 1,067 $ 365 $ 6 $ — $ 1,438 Gross Additions to Long-Lived Assets $ 2,896 $ 996 $ 20 $ — $ 3,912 As of December 31, 2018 Total Assets $ 31,109 $ 12,594 $ 2,604 $ (981 ) $ 45,326 Investments in Equity Method Subsidiaries $ — $ 86 $ — $ — $ 86 PSE&G Power Other (A) Eliminations (B) Consolidated Total Millions Year Ended December 31, 2017 Operating Revenues $ 6,324 $ 3,860 $ 466 $ (1,556 ) $ 9,094 Depreciation and Amortization 685 1,268 33 — 1,986 Operating Income (Loss) 1,760 (367 ) 36 — 1,429 Income from Equity Method Investments — 14 — — 14 Interest Income 24 3 5 (2 ) 30 Interest Expense 303 50 40 (2 ) 391 Income (Loss) before Income Taxes 1,536 (250 ) (18 ) — 1,268 Income Tax Expense (Benefit) 563 (729 ) (140 ) — (306 ) Net Income (Loss) $ 973 $ 479 $ 122 $ — $ 1,574 Gross Additions to Long-Lived Assets $ 2,919 $ 1,231 $ 40 $ — $ 4,190 As of December 31, 2017 Total Assets $ 28,554 $ 12,418 $ 2,666 $ (922 ) $ 42,716 Investments in Equity Method Subsidiaries $ — $ 87 $ — $ — $ 87 PSE&G Power Other (A) Eliminations (B) Consolidated Total Millions Year Ended December 31, 2016 Operating Revenues $ 6,303 $ 3,861 $ 370 $ (1,568 ) $ 8,966 Depreciation and Amortization 565 881 30 — 1,476 Operating Income (Loss) 1,629 17 (48 ) — 1,598 Income from Equity Method Investments — 11 — — 11 Interest Income 24 4 4 (2 ) 30 Interest Expense 289 84 14 (2 ) 385 Income (Loss) before Income Taxes 1,404 (43 ) (63 ) — 1,298 Income Tax Expense (Benefit) 515 (61 ) (43 ) — 411 Net Income (Loss) $ 889 $ 18 $ (20 ) $ — $ 887 Gross Additions to Long-Lived Assets $ 2,816 $ 1,343 $ 40 $ — $ 4,199 As of December 31, 2016 Total Assets $ 26,288 $ 12,193 $ 2,373 $ (784 ) $ 40,070 Investments in Equity Method Subsidiaries $ — $ 102 $ — $ — $ 102 (A) Includes amounts applicable to Energy Holdings and PSEG LI, which are below the quantitative threshold for separate disclosure as reportable segments. Other also includes amounts applicable to PSEG (parent corporation) and Services. (B) Intercompany eliminations primarily relate to intercompany transactions between PSE&G and Power. For a further discussion of the intercompany transactions between PSE&G and Power, see Note 25. Related-Party Transactions .

Related-Party Transactions

Related-Party Transactions	12 Months Ended
	Dec. 31, 2018
Related Party Transaction [Line Items]
Related-Party Transactions	Related-Party Transactions The following discussion relates to intercompany transactions, which are eliminated during the PSEG consolidation process in accordance with GAAP. PSE&G The financial statements for PSE&G include transactions with related parties presented as follows: Years Ended December 31, Related Party Transactions 2018 2017 2016 Millions Billings from Affiliates: Net Billings from Power primarily through BGS and BGSS (A) $ 1,514 $ 1,580 $ 1,587 Administrative Billings from Services (B) 333 331 312 Total Billings from Affiliates $ 1,847 $ 1,911 $ 1,899 Years Ended December 31, Related Party Transactions 2018 2017 Millions Receivables from PSEG (C) $ 123 $ — Payable to Power (A) $ 245 $ 221 Payable to Services (B) 76 78 Payable to PSEG (C) — 41 Accounts Payable—Affiliated Companies $ 321 $ 340 Working Capital Advances to Services (D) $ 33 $ 33 Long-Term Accrued Taxes Payable $ 69 $ 91 Power The financial statements for Power include transactions with related parties presented as follows: Years Ended December 31, Related Party Transactions 2018 2017 2016 Millions Billings to Affiliates: Net Billings to PSE&G primarily through BGS and BGSS (A) $ 1,514 $ 1,580 1,587 Billings from Affiliates: Administrative Billings from Services (B) $ 145 $ 168 $ 179 Years Ended December 31, Related Party Transactions 2018 2017 Millions Receivable from PSE&G (A) $ 245 $ 221 Receivables from PSEG (C) 29 — Accounts Receivable—Affiliated Companies $ 274 $ 221 Payable to Services (B) $ 16 $ 28 Payable to PSEG (C) — 29 Accounts Payable—Affiliated Companies $ 16 $ 57 Short-Term Loan due to Affiliate (E) $ 193 $ 281 Working Capital Advances to Services (D) $ 17 $ 17 Long-Term Accrued Taxes Payable $ 76 $ 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 Consolidated Balance Sheets. (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.
PSE&G [Member]
Related Party Transaction [Line Items]
Related-Party Transactions	Related-Party Transactions The following discussion relates to intercompany transactions, which are eliminated during the PSEG consolidation process in accordance with GAAP. PSE&G The financial statements for PSE&G include transactions with related parties presented as follows: Years Ended December 31, Related Party Transactions 2018 2017 2016 Millions Billings from Affiliates: Net Billings from Power primarily through BGS and BGSS (A) $ 1,514 $ 1,580 $ 1,587 Administrative Billings from Services (B) 333 331 312 Total Billings from Affiliates $ 1,847 $ 1,911 $ 1,899 Years Ended December 31, Related Party Transactions 2018 2017 Millions Receivables from PSEG (C) $ 123 $ — Payable to Power (A) $ 245 $ 221 Payable to Services (B) 76 78 Payable to PSEG (C) — 41 Accounts Payable—Affiliated Companies $ 321 $ 340 Working Capital Advances to Services (D) $ 33 $ 33 Long-Term Accrued Taxes Payable $ 69 $ 91 Power The financial statements for Power include transactions with related parties presented as follows: Years Ended December 31, Related Party Transactions 2018 2017 2016 Millions Billings to Affiliates: Net Billings to PSE&G primarily through BGS and BGSS (A) $ 1,514 $ 1,580 1,587 Billings from Affiliates: Administrative Billings from Services (B) $ 145 $ 168 $ 179 Years Ended December 31, Related Party Transactions 2018 2017 Millions Receivable from PSE&G (A) $ 245 $ 221 Receivables from PSEG (C) 29 — Accounts Receivable—Affiliated Companies $ 274 $ 221 Payable to Services (B) $ 16 $ 28 Payable to PSEG (C) — 29 Accounts Payable—Affiliated Companies $ 16 $ 57 Short-Term Loan due to Affiliate (E) $ 193 $ 281 Working Capital Advances to Services (D) $ 17 $ 17 Long-Term Accrued Taxes Payable $ 76 $ 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 Consolidated Balance Sheets. (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.
Power [Member]
Related Party Transaction [Line Items]
Related-Party Transactions	Related-Party Transactions The following discussion relates to intercompany transactions, which are eliminated during the PSEG consolidation process in accordance with GAAP. PSE&G The financial statements for PSE&G include transactions with related parties presented as follows: Years Ended December 31, Related Party Transactions 2018 2017 2016 Millions Billings from Affiliates: Net Billings from Power primarily through BGS and BGSS (A) $ 1,514 $ 1,580 $ 1,587 Administrative Billings from Services (B) 333 331 312 Total Billings from Affiliates $ 1,847 $ 1,911 $ 1,899 Years Ended December 31, Related Party Transactions 2018 2017 Millions Receivables from PSEG (C) $ 123 $ — Payable to Power (A) $ 245 $ 221 Payable to Services (B) 76 78 Payable to PSEG (C) — 41 Accounts Payable—Affiliated Companies $ 321 $ 340 Working Capital Advances to Services (D) $ 33 $ 33 Long-Term Accrued Taxes Payable $ 69 $ 91 Power The financial statements for Power include transactions with related parties presented as follows: Years Ended December 31, Related Party Transactions 2018 2017 2016 Millions Billings to Affiliates: Net Billings to PSE&G primarily through BGS and BGSS (A) $ 1,514 $ 1,580 1,587 Billings from Affiliates: Administrative Billings from Services (B) $ 145 $ 168 $ 179 Years Ended December 31, Related Party Transactions 2018 2017 Millions Receivable from PSE&G (A) $ 245 $ 221 Receivables from PSEG (C) 29 — Accounts Receivable—Affiliated Companies $ 274 $ 221 Payable to Services (B) $ 16 $ 28 Payable to PSEG (C) — 29 Accounts Payable—Affiliated Companies $ 16 $ 57 Short-Term Loan due to Affiliate (E) $ 193 $ 281 Working Capital Advances to Services (D) $ 17 $ 17 Long-Term Accrued Taxes Payable $ 76 $ 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 Consolidated Balance Sheets. (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.

Selected Quarterly Data

Selected Quarterly Data	12 Months Ended
	Dec. 31, 2018
Schedule of Quarterly Data [Line Items]
Selected Quarterly Data	Selected Quarterly Data (Unaudited) The information shown in the following tables, in the opinion of PSEG, PSE&G and Power includes all adjustments, consisting only of normal recurring accruals, necessary to fairly present such amounts. Quarter Ended March 31, (A) June 30, (A) September 30, December 31, (A) 2018 2017 2018 2017 2018 2017 2018 2017 PSEG Consolidated: Millions, except per share data Operating Revenues $ 2,818 $ 2,591 $ 2,016 $ 2,142 $ 2,394 $ 2,254 $ 2,468 $ 2,107 Operating Income $ 832 $ 178 $ 411 $ 195 $ 554 $ 693 $ 501 $ 363 Net Income $ 558 $ 114 $ 269 $ 109 $ 412 $ 395 $ 199 $ 956 Earnings Per Share: Basic: Net Income $ 1.11 $ 0.23 $ 0.53 $ 0.22 $ 0.82 $ 0.78 $ 0.39 $ 1.89 Diluted: Net Income $ 1.10 $ 0.22 $ 0.53 $ 0.22 $ 0.81 $ 0.78 $ 0.39 $ 1.88 Weighted Average Common Shares Outstanding: Basic 504 505 504 505 504 505 504 505 Diluted 507 508 507 507 507 507 508 508 Quarter Ended March 31, June 30, September 30, December 31, 2018 2017 2018 2017 2018 2017 2018 2017 PSE&G: Millions Operating Revenues $ 1,845 $ 1,826 $ 1,386 $ 1,393 $ 1,595 $ 1,530 $ 1,645 $ 1,575 Operating Income $ 482 $ 523 $ 358 $ 380 $ 421 $ 461 $ 345 $ 396 Net Income $ 319 $ 299 $ 231 $ 208 $ 278 $ 246 $ 239 $ 220 Quarter Ended March 31, (A) June 30, (A) September 30, December 31, (A) 2018 2017 2018 2017 2018 2017 2018 2017 Power: Millions Operating Revenues $ 1,403 $ 1,269 $ 767 $ 918 $ 868 $ 846 $ 1,108 $ 827 Operating Income (Loss) $ 329 $ (305 ) $ 42 $ (189 ) $ 112 $ 211 $ 113 $ (84 ) Net Income (Loss) $ 234 $ (170 ) $ 41 $ (97 ) $ 125 $ 136 $ (35 ) $ 610 (A) The increases in Operating Income at PSEG consolidated and Power in the first and second quarters of 2018 as compared to the same quarters in 2017 were primarily due to higher costs in 2017 related to closing the coal/gas Hudson and Mercer units, which were fully depreciated as of June 1, 2017. The increases in Operating Income at PSEG consolidated and Power in the fourth quarter 2018 as compared to the same quarter in 2017 were primarily due to lower MTM losses and a gain on the sale of the Hudson and Mercer units. The decreases in Net Income at PSEG consolidated and Power in the fourth quarter 2018 as compared to the same quarter in 2017 also reflected the impact of the one-time benefit recorded in December 2017 as a result of the remeasurement of deferred tax balances and the inclusion in 2018 of net unrealized losses on equity investments in the NDT Fund in accordance with new accounting guidance.
PSE&G [Member]
Schedule of Quarterly Data [Line Items]
Selected Quarterly Data	Selected Quarterly Data (Unaudited) The information shown in the following tables, in the opinion of PSEG, PSE&G and Power includes all adjustments, consisting only of normal recurring accruals, necessary to fairly present such amounts. Quarter Ended March 31, (A) June 30, (A) September 30, December 31, (A) 2018 2017 2018 2017 2018 2017 2018 2017 PSEG Consolidated: Millions, except per share data Operating Revenues $ 2,818 $ 2,591 $ 2,016 $ 2,142 $ 2,394 $ 2,254 $ 2,468 $ 2,107 Operating Income $ 832 $ 178 $ 411 $ 195 $ 554 $ 693 $ 501 $ 363 Net Income $ 558 $ 114 $ 269 $ 109 $ 412 $ 395 $ 199 $ 956 Earnings Per Share: Basic: Net Income $ 1.11 $ 0.23 $ 0.53 $ 0.22 $ 0.82 $ 0.78 $ 0.39 $ 1.89 Diluted: Net Income $ 1.10 $ 0.22 $ 0.53 $ 0.22 $ 0.81 $ 0.78 $ 0.39 $ 1.88 Weighted Average Common Shares Outstanding: Basic 504 505 504 505 504 505 504 505 Diluted 507 508 507 507 507 507 508 508 Quarter Ended March 31, June 30, September 30, December 31, 2018 2017 2018 2017 2018 2017 2018 2017 PSE&G: Millions Operating Revenues $ 1,845 $ 1,826 $ 1,386 $ 1,393 $ 1,595 $ 1,530 $ 1,645 $ 1,575 Operating Income $ 482 $ 523 $ 358 $ 380 $ 421 $ 461 $ 345 $ 396 Net Income $ 319 $ 299 $ 231 $ 208 $ 278 $ 246 $ 239 $ 220 Quarter Ended March 31, (A) June 30, (A) September 30, December 31, (A) 2018 2017 2018 2017 2018 2017 2018 2017 Power: Millions Operating Revenues $ 1,403 $ 1,269 $ 767 $ 918 $ 868 $ 846 $ 1,108 $ 827 Operating Income (Loss) $ 329 $ (305 ) $ 42 $ (189 ) $ 112 $ 211 $ 113 $ (84 ) Net Income (Loss) $ 234 $ (170 ) $ 41 $ (97 ) $ 125 $ 136 $ (35 ) $ 610 (A) The increases in Operating Income at PSEG consolidated and Power in the first and second quarters of 2018 as compared to the same quarters in 2017 were primarily due to higher costs in 2017 related to closing the coal/gas Hudson and Mercer units, which were fully depreciated as of June 1, 2017. The increases in Operating Income at PSEG consolidated and Power in the fourth quarter 2018 as compared to the same quarter in 2017 were primarily due to lower MTM losses and a gain on the sale of the Hudson and Mercer units. The decreases in Net Income at PSEG consolidated and Power in the fourth quarter 2018 as compared to the same quarter in 2017 also reflected the impact of the one-time benefit recorded in December 2017 as a result of the remeasurement of deferred tax balances and the inclusion in 2018 of net unrealized losses on equity investments in the NDT Fund in accordance with new accounting guidance.
Power [Member]
Schedule of Quarterly Data [Line Items]
Selected Quarterly Data	Selected Quarterly Data (Unaudited) The information shown in the following tables, in the opinion of PSEG, PSE&G and Power includes all adjustments, consisting only of normal recurring accruals, necessary to fairly present such amounts. Quarter Ended March 31, (A) June 30, (A) September 30, December 31, (A) 2018 2017 2018 2017 2018 2017 2018 2017 PSEG Consolidated: Millions, except per share data Operating Revenues $ 2,818 $ 2,591 $ 2,016 $ 2,142 $ 2,394 $ 2,254 $ 2,468 $ 2,107 Operating Income $ 832 $ 178 $ 411 $ 195 $ 554 $ 693 $ 501 $ 363 Net Income $ 558 $ 114 $ 269 $ 109 $ 412 $ 395 $ 199 $ 956 Earnings Per Share: Basic: Net Income $ 1.11 $ 0.23 $ 0.53 $ 0.22 $ 0.82 $ 0.78 $ 0.39 $ 1.89 Diluted: Net Income $ 1.10 $ 0.22 $ 0.53 $ 0.22 $ 0.81 $ 0.78 $ 0.39 $ 1.88 Weighted Average Common Shares Outstanding: Basic 504 505 504 505 504 505 504 505 Diluted 507 508 507 507 507 507 508 508 Quarter Ended March 31, June 30, September 30, December 31, 2018 2017 2018 2017 2018 2017 2018 2017 PSE&G: Millions Operating Revenues $ 1,845 $ 1,826 $ 1,386 $ 1,393 $ 1,595 $ 1,530 $ 1,645 $ 1,575 Operating Income $ 482 $ 523 $ 358 $ 380 $ 421 $ 461 $ 345 $ 396 Net Income $ 319 $ 299 $ 231 $ 208 $ 278 $ 246 $ 239 $ 220 Quarter Ended March 31, (A) June 30, (A) September 30, December 31, (A) 2018 2017 2018 2017 2018 2017 2018 2017 Power: Millions Operating Revenues $ 1,403 $ 1,269 $ 767 $ 918 $ 868 $ 846 $ 1,108 $ 827 Operating Income (Loss) $ 329 $ (305 ) $ 42 $ (189 ) $ 112 $ 211 $ 113 $ (84 ) Net Income (Loss) $ 234 $ (170 ) $ 41 $ (97 ) $ 125 $ 136 $ (35 ) $ 610 (A) The increases in Operating Income at PSEG consolidated and Power in the first and second quarters of 2018 as compared to the same quarters in 2017 were primarily due to higher costs in 2017 related to closing the coal/gas Hudson and Mercer units, which were fully depreciated as of June 1, 2017. The increases in Operating Income at PSEG consolidated and Power in the fourth quarter 2018 as compared to the same quarter in 2017 were primarily due to lower MTM losses and a gain on the sale of the Hudson and Mercer units. The decreases in Net Income at PSEG consolidated and Power in the fourth quarter 2018 as compared to the same quarter in 2017 also reflected the impact of the one-time benefit recorded in December 2017 as a result of the remeasurement of deferred tax balances and the inclusion in 2018 of net unrealized losses on equity investments in the NDT Fund in accordance with new accounting guidance.

Guarantees of Debt

Guarantees of Debt	12 Months Ended
	Dec. 31, 2018
Guarantees of Debt [Line Items]
Guarantees of Debt	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 December 31, 2018 and 2017 and for the years ended December 31, 2018 , 2017 and 2016 . Power Guarantor Subsidiaries Other Subsidiaries Consolidating Adjustments Total Millions Year Ended December 31, 2018 Operating Revenues $ — $ 4,078 $ 224 $ (156 ) $ 4,146 Operating Expenses 14 3,460 232 (156 ) 3,550 Operating Income (Loss) (14 ) 618 (8 ) — 596 Equity Earnings (Losses) of Subsidiaries 406 (28 ) 15 (378 ) 15 Net Gains (Losses) on Trust Investments (1 ) (139 ) — — (140 ) Other Income (Deductions) 135 166 — (280 ) 21 Non-Operating Pension and OPEB Credits (Costs) — 13 2 — 15 Interest Expense (230 ) (96 ) (30 ) 280 (76 ) Income Tax Benefit (Expense) 69 (143 ) 8 — (66 ) Net Income (Loss) $ 365 $ 391 $ (13 ) $ (378 ) $ 365 Comprehensive Income (Loss) $ 393 $ 379 $ (13 ) $ (366 ) $ 393 As of December 31, 2018 Current Assets $ 4,317 $ 1,479 $ 304 $ (4,593 ) $ 1,507 Property, Plant and Equipment, net 49 4,971 3,822 — 8,842 Investment in Subsidiaries 5,062 1,107 — (6,169 ) — Noncurrent Assets 273 2,109 101 (238 ) 2,245 Total Assets $ 9,701 $ 9,666 $ 4,227 $ (11,000 ) $ 12,594 Current Liabilities $ 437 $ 2,971 $ 2,027 $ (4,593 ) $ 842 Noncurrent Liabilities 513 1,996 730 (238 ) 3,001 Long-Term Debt 2,791 — — — 2,791 Member’s Equity 5,960 4,699 1,470 (6,169 ) 5,960 Total Liabilities and Member’s Equity $ 9,701 $ 9,666 $ 4,227 $ (11,000 ) $ 12,594 Year Ended December 31, 2018 Net Cash Provided By (Used In) Operating Activities $ (74 ) $ 1,007 $ 42 $ 109 $ 1,084 Net Cash Provided By (Used In) Investing Activities $ (402 ) $ (1,034 ) $ (406 ) $ 791 $ (1,051 ) Net Cash Provided By (Used In) Financing Activities $ 476 $ 27 $ 354 $ (900 ) $ (43 ) Power Guarantor Subsidiaries Other Subsidiaries Consolidating Adjustments Total Millions Year Ended December 31, 2017 Operating Revenues $ — $ 3,821 $ 174 $ (135 ) $ 3,860 Operating Expenses 8 4,159 195 (135 ) 4,227 Operating Income (Loss) (8 ) (338 ) (21 ) — (367 ) Equity Earnings (Losses) of Subsidiaries 567 60 14 (627 ) 14 Net Gains (Losses) on Trust Investments 3 122 — — 125 Other Income (Deductions) 71 91 2 (144 ) 20 Non-Operating Pension and OPEB Credits (Costs) — 8 — — 8 Interest Expense (128 ) (49 ) (17 ) 144 (50 ) Income Tax Benefit (Expense) (26 ) 588 167 — 729 Net Income (Loss) $ 479 $ 482 $ 145 $ (627 ) $ 479 Comprehensive Income (Loss) $ 518 $ 529 $ 145 $ (674 ) $ 518 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 Year Ended December 31, 2017 Net Cash Provided By (Used In) Operating Activities $ (42 ) $ 1,185 $ 238 $ (55 ) $ 1,326 Net Cash Provided By (Used In) Investing Activities $ 506 $ (448 ) $ (525 ) $ (765 ) $ (1,232 ) Net Cash Provided By (Used In) Financing Activities $ (464 ) $ (736 ) $ 307 $ 820 $ (73 ) Power Guarantor Subsidiaries Other Subsidiaries Consolidating Adjustments Total Millions Year Ended December 31, 2016 Operating Revenues $ — $ 3,809 $ 173 $ (121 ) $ 3,861 Operating Expenses 8 3,796 161 (121 ) 3,844 Operating Income (Loss) (8 ) 13 12 — 17 Equity Earnings (Losses) of Subsidiaries 36 (3 ) 11 (33 ) 11 Net Gains (Losses) on Trust Investments 1 (7 ) — — (6 ) Other Income (Deductions) 52 60 — (89 ) 23 Non-Operating Pension and OPEB Credits (Costs) — (4 ) — — (4 ) Interest Expense (115 ) (40 ) (18 ) 89 (84 ) Income Tax Benefit (Expense) 52 (11 ) 20 — 61 Net Income (Loss) $ 18 $ 8 $ 25 $ (33 ) $ 18 Comprehensive Income (Loss) $ 47 $ 50 $ 25 $ (75 ) $ 47 Year Ended December 31, 2016 Net Cash Provided By (Used In) Operating Activities $ 97 $ 1,442 $ 323 $ (607 ) $ 1,255 Net Cash Provided By (Used In) Investing Activities $ 60 $ (707 ) $ (789 ) $ 289 $ (1,147 ) Net Cash Provided By (Used In) Financing Activities $ (157 ) $ (736 ) $ 466 $ 318 $ (109 )
Power [Member]
Guarantees of Debt [Line Items]
Guarantees of Debt	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 December 31, 2018 and 2017 and for the years ended December 31, 2018 , 2017 and 2016 . Power Guarantor Subsidiaries Other Subsidiaries Consolidating Adjustments Total Millions Year Ended December 31, 2018 Operating Revenues $ — $ 4,078 $ 224 $ (156 ) $ 4,146 Operating Expenses 14 3,460 232 (156 ) 3,550 Operating Income (Loss) (14 ) 618 (8 ) — 596 Equity Earnings (Losses) of Subsidiaries 406 (28 ) 15 (378 ) 15 Net Gains (Losses) on Trust Investments (1 ) (139 ) — — (140 ) Other Income (Deductions) 135 166 — (280 ) 21 Non-Operating Pension and OPEB Credits (Costs) — 13 2 — 15 Interest Expense (230 ) (96 ) (30 ) 280 (76 ) Income Tax Benefit (Expense) 69 (143 ) 8 — (66 ) Net Income (Loss) $ 365 $ 391 $ (13 ) $ (378 ) $ 365 Comprehensive Income (Loss) $ 393 $ 379 $ (13 ) $ (366 ) $ 393 As of December 31, 2018 Current Assets $ 4,317 $ 1,479 $ 304 $ (4,593 ) $ 1,507 Property, Plant and Equipment, net 49 4,971 3,822 — 8,842 Investment in Subsidiaries 5,062 1,107 — (6,169 ) — Noncurrent Assets 273 2,109 101 (238 ) 2,245 Total Assets $ 9,701 $ 9,666 $ 4,227 $ (11,000 ) $ 12,594 Current Liabilities $ 437 $ 2,971 $ 2,027 $ (4,593 ) $ 842 Noncurrent Liabilities 513 1,996 730 (238 ) 3,001 Long-Term Debt 2,791 — — — 2,791 Member’s Equity 5,960 4,699 1,470 (6,169 ) 5,960 Total Liabilities and Member’s Equity $ 9,701 $ 9,666 $ 4,227 $ (11,000 ) $ 12,594 Year Ended December 31, 2018 Net Cash Provided By (Used In) Operating Activities $ (74 ) $ 1,007 $ 42 $ 109 $ 1,084 Net Cash Provided By (Used In) Investing Activities $ (402 ) $ (1,034 ) $ (406 ) $ 791 $ (1,051 ) Net Cash Provided By (Used In) Financing Activities $ 476 $ 27 $ 354 $ (900 ) $ (43 ) Power Guarantor Subsidiaries Other Subsidiaries Consolidating Adjustments Total Millions Year Ended December 31, 2017 Operating Revenues $ — $ 3,821 $ 174 $ (135 ) $ 3,860 Operating Expenses 8 4,159 195 (135 ) 4,227 Operating Income (Loss) (8 ) (338 ) (21 ) — (367 ) Equity Earnings (Losses) of Subsidiaries 567 60 14 (627 ) 14 Net Gains (Losses) on Trust Investments 3 122 — — 125 Other Income (Deductions) 71 91 2 (144 ) 20 Non-Operating Pension and OPEB Credits (Costs) — 8 — — 8 Interest Expense (128 ) (49 ) (17 ) 144 (50 ) Income Tax Benefit (Expense) (26 ) 588 167 — 729 Net Income (Loss) $ 479 $ 482 $ 145 $ (627 ) $ 479 Comprehensive Income (Loss) $ 518 $ 529 $ 145 $ (674 ) $ 518 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 Year Ended December 31, 2017 Net Cash Provided By (Used In) Operating Activities $ (42 ) $ 1,185 $ 238 $ (55 ) $ 1,326 Net Cash Provided By (Used In) Investing Activities $ 506 $ (448 ) $ (525 ) $ (765 ) $ (1,232 ) Net Cash Provided By (Used In) Financing Activities $ (464 ) $ (736 ) $ 307 $ 820 $ (73 ) Power Guarantor Subsidiaries Other Subsidiaries Consolidating Adjustments Total Millions Year Ended December 31, 2016 Operating Revenues $ — $ 3,809 $ 173 $ (121 ) $ 3,861 Operating Expenses 8 3,796 161 (121 ) 3,844 Operating Income (Loss) (8 ) 13 12 — 17 Equity Earnings (Losses) of Subsidiaries 36 (3 ) 11 (33 ) 11 Net Gains (Losses) on Trust Investments 1 (7 ) — — (6 ) Other Income (Deductions) 52 60 — (89 ) 23 Non-Operating Pension and OPEB Credits (Costs) — (4 ) — — (4 ) Interest Expense (115 ) (40 ) (18 ) 89 (84 ) Income Tax Benefit (Expense) 52 (11 ) 20 — 61 Net Income (Loss) $ 18 $ 8 $ 25 $ (33 ) $ 18 Comprehensive Income (Loss) $ 47 $ 50 $ 25 $ (75 ) $ 47 Year Ended December 31, 2016 Net Cash Provided By (Used In) Operating Activities $ 97 $ 1,442 $ 323 $ (607 ) $ 1,255 Net Cash Provided By (Used In) Investing Activities $ 60 $ (707 ) $ (789 ) $ 289 $ (1,147 ) Net Cash Provided By (Used In) Financing Activities $ (157 ) $ (736 ) $ 466 $ 318 $ (109 )

Valuation And Qualifying Accoun

Valuation And Qualifying Accounts	12 Months Ended
	Dec. 31, 2018
SEC Schedule, 12-09, Valuation and Qualifying Accounts [Abstract]
Valuation And Qualifying Accounts	PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED Column A Column B Column C Additions Column D Column E Description Balance at Beginning of Period Charged to cost and expenses Charged to other accounts- describe Deductions- describe Balance at End of Period Millions 2018 Allowance for Doubtful Accounts $ 59 $ 91 $ — $ 87 (A) $ 63 Materials and Supplies Valuation Reserve 7 4 — 2 (B) 9 2017 Allowance for Doubtful Accounts $ 68 $ 76 $ — $ 85 (A) $ 59 Materials and Supplies Valuation Reserve 37 2 — 32 (C) 7 2016 Allowance for Doubtful Accounts $ 67 $ 85 $ — $ 84 (A) $ 68 Materials and Supplies Valuation Reserve 11 32 — 6 (B) 37 (A) Accounts Receivable written off. (B) Reduce reserve to appropriate level and to remove obsolete inventory. (C) Hudson and Mercer inventory written off. PUBLIC SERVICE ELECTRIC AND GAS COMPANY Column A Column B Column C Additions Column D Column E Description Balance at Beginning of Period Charged to cost and expenses Charged to other accounts- describe Deductions- describe Balance at End of Period Millions 2018 Allowance for Doubtful Accounts $ 59 $ 91 $ — $ 87 (A) $ 63 Materials and Supplies Valuation Reserve — 2 — — 2 2017 Allowance for Doubtful Accounts $ 68 $ 76 $ — $ 85 (A) $ 59 Materials and Supplies Valuation Reserve — — — — — 2016 Allowance for Doubtful Accounts $ 67 $ 85 $ — $ 84 (A) $ 68 Materials and Supplies Valuation Reserve 1 — — 1 (B) — (A) Accounts Receivable written off. (B) Reduce reserve to appropriate level and to remove obsolete inventory. PSEG POWER LLC Column A Column B Column C Additions Column D Column E Description Balance at Beginning of Period Charged to cost and expenses Charged to other accounts- describe Deductions- describe Balance at End of Period Millions 2018 Materials and Supplies Valuation Reserve $ 7 $ 2 $ — $ 2 (A) $ 7 2017 Materials and Supplies Valuation Reserve $ 37 $ 2 $ — $ 32 (B) $ 7 2016 Materials and Supplies Valuation Reserve $ 10 $ 32 $ — $ 5 (A) $ 37 (A) Reduce reserve to appropriate level and to remove obsolete inventory. (B) Hudson and Mercer inventory written off.

Organization, Basis Of Presen_2

Organization, Basis Of Presentation And Summary Of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2018
Accounting Policies
Basis Of Presentation	Basis of Presentation The respective financial statements included herein have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (SEC) applicable to Annual Reports on Form 10-K and in accordance with accounting guidance generally accepted in the United States (GAAP).
Principles Of Consolidation	Principles of Consolidation Each company consolidates those entities in which it has a controlling interest or is the primary beneficiary. See Note 5. Variable Interest Entity . Entities over which the companies exhibit significant influence, but do not have a controlling interest and/or are not the primary beneficiary, are accounted for under the equity method of accounting. For investments in which significant influence does not exist and the investor is not the primary beneficiary, the cost method of accounting is applied. All significant intercompany accounts and transactions are eliminated in consolidation. PSE&G and Power also have undivided interests in certain jointly-owned facilities, with each responsible for paying its respective ownership share of construction costs, fuel purchases and operating expenses. PSE&G and Power consolidate their portion of any revenues and expenses related to their respective jointly-owned facilities in the appropriate revenue and expense categories.
Accounting For The Effects Of Regulation	Accounting for the Effects of Regulation In accordance with accounting guidance for rate-regulated entities, PSE&G’s financial statements reflect the economic effects of regulation. PSE&G defers the recognition of costs (a Regulatory Asset) or records the recognition of obligations (a Regulatory Liability) if it is probable that, through the rate-making process, there will be a corresponding increase or decrease in future rates. Accordingly, PSE&G has deferred certain costs and recoveries, which are being amortized over various future periods. To the extent that collection of any such costs or payment of liabilities becomes no longer probable as a result of changes in regulation and/or competitive position, the associated Regulatory Asset or Liability is charged or credited to income. Management believes that PSE&G’s T&D businesses continue to meet the accounting requirements for rate-regulated entities. For additional information, see Note 7. Regulatory Assets and Liabilities .
Derivative Financial Instruments	Derivative Instruments Each company uses derivative instruments to manage risk pursuant to its business plans and prudent practices. Within PSEG and its affiliate companies, Power has the most exposure to commodity price risk. Power is exposed to commodity price risk primarily relating to changes in the market price of electricity, fossil fuels and other commodities. Fluctuations in market prices result from changes in supply and demand, fuel costs, market conditions, weather, state and federal regulatory policies, environmental policies, transmission availability and other factors. Power uses a variety of derivative and non-derivative instruments, such as financial options, futures, swaps, fuel purchases and forward purchases and sales of electricity, to manage the exposure to fluctuations in commodity prices and optimize the value of Power’s expected generation. Changes in the fair market value of the derivative contracts are recorded in earnings. Determining whether a contract qualifies as a derivative requires that management exercise significant judgment, including assessing the contract’s market liquidity. PSEG has determined that contracts to purchase and sell certain products do not meet the definition of a derivative under the current authoritative guidance since they do not provide for net settlement, or the markets are not sufficiently liquid to conclude that physical forward contracts are readily convertible to cash. Under current authoritative guidance, all derivatives are recognized on the balance sheet at their fair value, except for derivatives that are designated as normal purchases and normal sales (NPNS). Further, derivatives that qualify for hedge accounting can be designated as fair value or cash flow hedges. For fair value hedges, changes in fair values for both the derivative and the underlying hedged exposure are recognized in earnings each period. Certain offsetting derivative assets and liabilities are subject to a master netting or similar agreement. In general, the terms of the agreements provide that in the event of an early termination the counterparties have the right to offset amounts owed or owing under that and any other agreement with the same counterparty. Accordingly, these positions are offset on the Consolidated Balance Sheets of Power and PSEG. For cash flow hedges, the portion of the derivative gain or loss that is effective in offsetting the change in the hedged cash flows of the underlying exposure is deferred in Accumulated Other Comprehensive Income (Loss) until earnings are affected by the variability of cash flows of the hedged transaction. Any hedge ineffectiveness is included in current period earnings. For derivative contracts that do not qualify or are not designated as cash flow or fair value hedges or as NPNS, changes in fair value are recorded in current period earnings. PSEG does not currently elect fair value or cash flow hedge accounting on its commodity derivative positions. Contracts that qualify for, and are designated, as NPNS are accounted for upon settlement. Contracts which qualify for NPNS are contracts for which physical delivery is probable, they will not be financially settled, and the quantities under contract are expected to be used or sold in the normal course of business over a reasonable period of time. For additional information regarding derivative financial instruments, see Note 17. Financial Risk Management Activities .
Revenue Recognition	Revenue Recognition PSE&G’s regulated electric and gas revenues are recorded primarily based on services rendered to customers. PSE&G records unbilled revenues for the estimated amount customers will be billed for services rendered from the time meters were last read to the end of the respective accounting period. The unbilled revenue is estimated each month based on usage per day, the number of unbilled days in the period, estimated seasonal loads based upon the time of year and the variance of actual degree-days and temperature-humidity-index hours of the unbilled period from expected norms. Regulated revenues from the transmission of electricity are recognized as services are provided based on a FERC-approved annual formula rate mechanism. This mechanism provides for an annual filing of estimated revenue requirement with rates effective January 1 of each year. After completion of the annual period ending December 31, PSE&G files a true-up whereby it compares its actual revenue requirement to the original estimate to determine any over or under collection of revenue. PSE&G records the estimated financial statement impact of the difference between the actual and the filed revenue requirement as a refund or deferral for future recovery when such amounts are probable and can be reasonably estimated in accordance with accounting guidance for rate-regulated entities. The majority of Power’s revenues relate to bilateral contracts, which are accounted for on the accrual basis as the energy is delivered. Power’s revenue also includes changes in the value of energy derivative contracts that are not designated as NPNS. See Note 17. Financial Risk Management Activities for further discussion. PJM Interconnection, L.L.C. (PJM), the Independent System Operator-New England (ISO-NE) and the New York Independent System Operator (NYISO) facilitate the dispatch of energy and energy-related products. Power generally reports electricity sales and purchases conducted with those individual ISOs on a net hourly basis in either Revenues or Energy Costs in its Consolidated Statement of Operations, the classification of which depends on the net hourly activity. Capacity revenue and expense is also reported net based on Power’s monthly net sale or purchase position in the individual ISOs. PSEG LI is the primary beneficiary of Long Island Electric Utility Servco, LLC (Servco). For transactions in which Servco acts as principal, Servco records revenues and the related pass-through expenditures separately in Operating Revenues and Operations and Maintenance (O&M) Expense, respectively. See Note 5. Variable Interest Entity for further information. The majority of Energy Holdings' revenues relate to its investments in leveraged leases. Income on leveraged leases is recognized by a method which produces a constant rate of return on the outstanding net investment in the lease, net of the related deferred tax liability, in the years in which the net investment is positive. Any gains or losses incurred as a result of a lease termination are recorded as revenues as these events occur in the ordinary course of business of managing the investment portfolio. For additional information regarding Revenues, see Note 3. Revenues .
Depreciation And Amortization	Depreciation and Amortization (D&A) PSE&G calculates depreciation under the straight-line method based on estimated average remaining lives of the several classes of depreciable property. These estimates are reviewed on a periodic basis and necessary adjustments are made as approved by the BPU or FERC. The depreciation rate stated as a percentage of original cost of depreciable property was as follows: 2018 2017 2016 Avg Rate Avg Rate Avg Rate Electric Transmission 2.42 % 2.41 % 2.39 % Electric Distribution 2.51 % 2.51 % 2.49 % Gas Distribution 1.61 % 1.63 % 1.63 % Power calculates depreciation on generation-related assets under the straight-line method based on the assets’ estimated useful lives. The estimated useful lives are: • general plant assets— 3 years to 20 years • fossil production assets— 30 years to 67 years • nuclear generation assets—approximately 60 years • pumped storage facilities— 76 years • solar assets— 25 years
Allowance for Funds Used During Construction (AFUDC) and Interest Capitalized During Construction	Allowance for Funds Used During Construction (AFUDC) and Interest Capitalized During Construction (IDC) AFUDC represents the cost of debt and equity funds used to finance the construction of new utility assets at PSE&G. IDC represents the cost of debt used to finance construction at Power. The amount of AFUDC or IDC capitalized as Property, Plant and Equipment is included as a reduction of interest charges or other income for the equity portion. The amounts and average rates used to calculate AFUDC or IDC for the years ended December 31, 2018 , 2017 and 2016 were as follows: AFUDC/IDC Capitalized 2018 2017 2016 Millions Avg Rate Millions Avg Rate Millions Avg Rate PSE&G $ 70 7.74 % $ 73 7.42 % $ 66 7.81 % Power $ 67 4.60 % $ 78 4.60 % $ 54 4.87 %
Income Taxes	Income Taxes PSEG and its subsidiaries file a consolidated federal income tax return and income taxes are allocated to PSEG’s subsidiaries based on the taxable income or loss of each subsidiary on a separate return basis in accordance with a tax sharing agreement between PSEG and each of its affiliated subsidiaries. Allocations between PSEG and its subsidiaries are recorded through intercompany accounts. Investment tax credits deferred in prior years are being amortized over the useful lives of the related property. Uncertain income tax positions are accounted for using a benefit recognition model with a two-step approach, a more-likely-than-not recognition criterion and a measurement attribute that measures the position as the largest amount of tax benefit that is greater than 50% likely of being realized upon ultimate settlement. If it is not more-likely-than-not that the benefit will be sustained on its technical merits, no benefit will be recorded. Uncertain tax positions that relate only to timing of when an item is included on a tax return are considered to have met the recognition threshold. See Note 21. Income Taxes for further discussion.
Impairment Of Long-Lived Assets	Impairment of Long-Lived Assets and Leveraged Leases Management evaluates long-lived assets for impairment whenever events or changes in circumstances, such as significant adverse changes in regulation, business climate, counterparty credit worthiness or market conditions, including prolonged periods of adverse commodity and capacity prices or a current expectation that a long-lived asset will be sold or disposed of significantly before the end of its previously estimated useful life, could potentially indicate an asset’s or asset group’s carrying amount may not be recoverable. In such an event, an undiscounted cash flow analysis is performed to determine if an impairment exists. When a long-lived asset’s or asset group’s carrying amount exceeds the associated undiscounted estimated future cash flows, the asset/asset group is considered impaired to the extent that its fair value is less than its carrying amount. An impairment would result in a reduction of the value of the long-lived asset/asset group through a non-cash charge to earnings. See Note 4. Early Plant Retirements for more information. For Power, cash flows for long-lived assets and asset groups are determined at the lowest level for which identifiable cash flows are largely independent of the cash flows of other assets and liabilities. The cash flows from the generation units are generally evaluated at a regional portfolio level (PJM, NYISO, ISO-NE) along with cash flows generated from the customer supply and risk management activities, inclusive of cash flows from contracts, including those that are accounted for as derivatives and meet the NPNS scope exception. In certain cases, generation assets are evaluated on an individual basis where those assets are individually contracted on a long-term basis with a third party and operations are independent of other generation assets (typically Power’s solar plants and Kalaeloa). Energy Holdings’ leveraged leases are comprised of Lease Receivables (net of non-recourse debt), the estimated residual value of leased assets, and unearned and deferred income. Residual values are the estimated values of the leased assets at the end of the respective lease per the original lease terms, net of any subsequent impairments. A review of the residual valuations, which are calculated by discounting the cash flows related to the leased assets after the lease term, is performed at least annually for each plant subject to lease using specific assumptions tailored to each plant. Those valuations are compared to the recorded residual values to determine if an impairment is warranted.
Cash And Cash Equivalents	Cash, Cash Equivalents and Restricted Cash Cash equivalents consist of short-term, highly liquid investments with original maturities of three months or less. Restricted cash consists primarily of deposits received related to various construction projects at PSE&G. The following provides a reconciliation of cash, cash equivalents and restricted cash reported within the Consolidated Balance Sheets that sum to the total of the same such amounts for the beginning ( December 31, 2017 ) and ending periods shown in the Consolidated Statements of Cash Flows for the year ended December 31, 2018 . PSE&G Power Other (A) Consolidated Millions As of December 31, 2017 Cash and Cash Equivalents $ 242 $ 32 $ 39 $ 313 Restricted Cash in Other Current Assets — — — — Restricted Cash in Other Noncurrent Assets 2 — — 2 Cash, Cash Equivalents and Restricted Cash $ 244 $ 32 $ 39 $ 315 As of December 31, 2018 Cash and Cash Equivalents $ 39 $ 22 $ 116 $ 177 Restricted Cash in Other Current Assets 8 — — 8 Restricted Cash in Other Noncurrent Assets 14 — — 14 Cash, Cash Equivalents and Restricted Cash $ 61 $ 22 $ 116 $ 199 (A) Includes amounts applicable to PSEG (parent corporation), Energy Holdings and Services.
Accounts Receivable-Allowance for Doubtful Accounts	Accounts Receivable—Allowance for Doubtful Accounts PSE&G’s accounts receivable are reported in the balance sheet as gross outstanding amounts adjusted for doubtful accounts. The allowance for doubtful accounts reflects PSE&G’s best estimates of losses on the accounts receivable balances. The allowance is based on accounts receivable aging, historical experience, write-off forecasts and other currently available evidence. Accounts receivable are charged off in the period in which the receivable is deemed uncollectible. Recoveries of accounts receivable are recorded when it is known they will be received.
Materials And Supplies And Fuel	Materials and Supplies and Fuel PSE&G’s and Power’s materials and supplies are carried at average cost and charged to inventory when purchased and expensed or capitalized to Property, Plant and Equipment, as appropriate, when installed or used. Fuel inventory at Power is valued at the lower of average cost or market and includes stored natural gas, coal, fuel oil and propane used to generate power and to satisfy obligations under Power’s gas supply contracts with PSE&G. The costs of fuel, including initial transportation costs, are included in inventory when purchased and charged to Energy Costs when used or sold. The cost of nuclear fuel is capitalized within Property, Plant and Equipment and amortized to fuel expense using the units-of-production method.
Property, Plant And Equipment	Property, Plant and Equipment PSE&G’s additions to and replacements of existing property, plant and equipment are capitalized at cost. The cost of maintenance, repair and replacement of minor items of property is charged to expense as incurred. At the time units of depreciable property are retired or otherwise disposed of, the original cost, adjusted for net salvage value, is charged to accumulated depreciation. Power capitalizes costs, including those related to its jointly-owned facilities, which increase the capacity, improve or extend the life of an existing asset, represent a newly acquired or constructed asset or represent the replacement of a retired asset. The cost of maintenance, repair and replacement of minor items of property is charged to appropriate expense accounts as incurred. Environmental costs are capitalized if the costs mitigate or prevent future environmental contamination or if the costs improve existing assets’ environmental safety or efficiency. All other environmental expenditures are expensed as incurred. Power also capitalizes spare parts that meet specific criteria. Capitalized spares are depreciated over the remaining lives of their associated assets.
Trust Investments	Trust Investments These securities comprise the Nuclear Decommissioning Trust (NDT) Fund, a master independent external trust account maintained to provide for the costs of decommissioning upon termination of operations of Power’s nuclear facilities and amounts that are deposited to fund a Rabbi Trust which was established to meet the obligations related to non-qualified pension plans and deferred compensation plans. Effective January 1, 2018, unrealized gains and losses on equity security investments are recorded in Net Income instead of Other Comprehensive Income (Loss). The debt securities continue to be classified as available-for-sale with the unrealized gains and losses recorded as a component of Accumulated Other Comprehensive Income (Loss). Realized gains and losses on both equity and available-for-sale debt security investments are recorded in earnings and are included with the unrealized gains and losses on equity securities in Net Gains (Losses) on Trust Investments. Other-than-temporary impairments on NDT and Rabbi Trust securities are also included in Net Gains (Losses) on Trust Investments. See Note 10. Trust Investments for further discussion.
Pension And Other Postretirement Benefits (OPEB) Plan Assets	Pension and Other Postretirement Benefits (OPEB) Plans The market-related value of plan assets held for the qualified pension and OPEB plans is equal to the fair value of those assets as of year-end. Fair value is determined using quoted market prices and independent pricing services based upon the security type as reported by the trustee at the measurement date (December 31) for all plan assets. PSEG recognizes a long-term receivable primarily related to future funding by LIPA of Servco’s recognized pension and OPEB liabilities. This receivable is presented separately on the Consolidated Balance Sheet of PSEG as a noncurrent asset. Pursuant to the OSA, Servco records expense for contributions to its pension plan trusts and for OPEB payments made to retirees. See Note 13. Pension, Other Postretirement Benefits (OPEB) and Savings Plan for further discussion.
Basis Adjustment	Basis Adjustment PSE&G and Power have recorded a Basis Adjustment in their respective Consolidated Balance Sheets related to the generation assets that were transferred from PSE&G to Power in August 2000 at the price specified by the BPU. Because the transfer was between affiliates, the transaction was recorded at the net book value of the assets and liabilities rather than the transfer price. The difference between the total transfer price and the net book value of the generation-related assets and liabilities, $986 million , net of tax, was recorded as a Basis Adjustment on PSE&G’s and Power’s Consolidated Balance Sheets. The $986 million is an addition to PSE&G’s Common Stockholder’s Equity and a reduction of Power’s Member’s Equity. These amounts are eliminated on PSEG’s consolidated financial statements.
Use Of Estimates	Use of Estimates The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
New Accounting Standards	New Standards Adopted in 2018 Revenue from Contracts With Customers — Accounting Standard Update (ASU) 2014-09, updated by ASUs 2015-14, 2016-08, 2016-10, 2016-12, 2016-20, 2017-13, 2017-14 This accounting standard, and related updates, were adopted on January 1, 2018 using the full retrospective transition method. There was no effect on Net Income as a result of adoption. However, certain retrospective adjustments were recorded in accordance with the new standard. At PSE&G, retrospective adjustments increased Operating Revenues by $90 million and $82 million , Energy Costs by $58 million and $77 million and O&M Expense by $32 million and $5 million for the years ended December 31, 2017 and 2016 , respectively. At Power, retrospective adjustments reduced Operating Revenues and Energy Costs by $70 million and $162 million for the years ended December 31, 2017 and 2016 , respectively. For disclosure requirements under this standard, including Nature of Goods and Services, Disaggregation of Revenues, and Remaining Performance Obligations under Fixed Consideration Contracts, see Note 3. Revenues . Recognition and Measurement of Financial Assets and Financial Liabilities—ASU 2016-01 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 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 adopted on January 1, 2018. Under the new guidance, equity investments in Power’s 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). 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 22. Accumulated Other Comprehensive Income (Loss), Net of Tax and Note 10. Trust Investments for further discussion. Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments—ASU 2016-15 This accounting standard reduces the diversity in practice in how certain cash receipts and cash payments are presented and classified in the Statement of Cash Flows. PSEG adopted this standard on January 1, 2018 using a retrospective transition method and had no changes in its presentation of its Statement of Cash Flows for each period presented. Statement of Cash Flows: Restricted Cash—ASU 2016-18 This accounting standard was adopted on 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 December 31, 2018 Consolidated Statements of Cash Flows was immaterial. Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (OPEB)—ASU 2017-07 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 year ended December 31, 2018 by approximately $58 million . The Consolidated Statements of Operations were recast to show retrospective adjustments of the non-service cost components of net benefit credits (costs) of $(8) million and $(15) million at PSE&G and $8 million and $(4) million at Power, for the years ended December 31, 2017 and 2016 , respectively, from O&M Expense to a new line item after Operating Income entitled Non-Operating Pension and OPEB Credits (Costs). See Note 13. Pension, Other Postretirement Benefits (OPEB) and Savings Plan . Stock Compensation - Scope of Modification Accounting—ASU 2017-09 This accounting standard was adopted on January 1, 2018. The standard will be applied prospectively to awards modified on or after January 1, 2018. There was no material impact on PSEG’s consolidated financial statements in 2018 from adoption of this new standard. New Standards Issued But Not Yet Adopted Leases — ASU 2016-02, updated by ASUs 2018-01, 2018-10, 2018-11 and 2018-20 This accounting standard, and related updates, replace existing lease accounting guidance and require lessees to recognize leases with a term greater than 12 months on the balance sheet using a right-of-use asset approach. At lease commencement, a lessee will recognize a lease asset and corresponding lease obligation. A lessee will classify its leases as either finance leases or operating leases and a lessor will classify its leases as operating leases, direct financing leases, or as sales-type leases. The standard requires additional disclosure of key information. Existing guidance related to leveraged leases does not change. Effective January 1, 2019, PSEG elected the prospective transition approach for all existing leases. There was no cumulative effect adjustment required to be recorded to Retained Earnings at adoption. P SEG elected various practical expedients allowed by the standard, including the package of three practical expedients related to not reassessing existing or expired contracts and initial direct costs; and excluding evaluation of land easements that exist or expired before adoption that were not previously accounted for as leases. The impact of adoption on PSEG’s Consolidated Balance Sheet was to increase its assets and liabilities by approximately $280 million . PSE&G’s assets and liabilities each increased by approximately $100 million and Power’s assets and liabilities each increased by approximately $50 million . PSEG’s adoption of this standard did not have a material impact on the Consolidated Statements of Operations or Consolidated Statements of Cash Flows of PSEG, PSE&G and Power. Derivatives and Hedging: Targeted Improvements to Accounting for Hedging Activities—ASU 2017-12, updated by ASU 2018-16 This accounting standard’s amendments more closely align hedge accounting with companies’ risk management activities in the financial statements and ease the operational burden of applying hedge accounting. The new guidance is effective for annual and interim periods beginning after December 15, 2018. PSEG adopted this standard on January 1, 2019. The standard requires using a modified retrospective method upon adoption. PSEG analyzed the impact of this standard on its consolidated financial statements and 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. Premium Amortization on Purchased Callable Debt Securities—ASU 2017-08 This accounting standard was issued to shorten the amortization period for certain callable debt securities held at a premium. Specifically, the standard requires the premium to be amortized to the earliest call date. The standard is effective for all entities for annual periods and interim periods within those annual periods beginning after December 15, 2018. PSEG adopted this standard on January 1, 2019 on a modified retrospective basis through a cumulative effect adjustment directly to Retained Earnings as of the beginning of 2019. Adoption of this standard did not have a material impact on PSEG’s financial statements. Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income—ASU 2018-02 This accounting standard affects any entity that is required to apply the provisions of the 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 allows entities to record a reclassification from Accumulated Other Comprehensive Income to Retained Earnings for stranded tax effects resulting from the recent decrease in the federal corporate income tax rate. The standard is effective for all entities for annual periods and interim periods within those annual periods beginning after December 15, 2018. PSEG adopted this standard on January 1, 2019. The impact of adoption on PSEG’s Consolidated Balance Sheet was to increase Retained Earnings and Accumulated Other Comprehensive Loss by approximately $81 million . Power’s Retained Earnings and Accumulated Other Comprehensive Loss increased by approximately $69 million . The impact on PSE&G’s Consolidated Balance Sheet was immaterial. PSEG’s adoption of this standard did not have a material impact on the Consolidated Statements of Operations or Consolidated Statements of Cash Flows of PSEG, PSE&G and Power. Measurement of Credit Losses on Financial Instruments — ASU 2016-13, updated by ASU 2018-19 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. Disclosure Framework — Changes to the Disclosure Requirements for Fair Value Measurement — ASU 2018-13 This accounting standard modifies the disclosure requirements for fair value measurements. Certain current disclosure requirements relating to Level 3 fair value measurements, and transfers between Level 1 and Level 2 fair value measurements will be eliminated. The standard will also add certain other disclosure requirements for Level 3 fair value measurements. The standard is effective for annual and interim periods beginning after December 15, 2019. Certain amendments in the standard should be applied prospectively for only the most recent interim or annual period presented in the initial fiscal year of adoption. All other amendments of the standard should be applied retrospectively to all periods presented upon their effective date. Early adoption is permitted. PSEG is currently analyzing the impact of this standard on its financial statements. Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract — ASU 2018-15 This accounting standard aligns the capitalization requirements for implementation costs incurred in a hosting arrangement that is a service contract with capitalization requirements for implementation costs incurred to develop or obtain internal-use software, including hosting arrangements that include an internal-use software license. The standard follows the guidance in ASC 350—Intangibles—Goodwill and Other to determine which implementation costs to capitalize as an asset related to the service contract and which costs to expense. The standard requires the amortization of capitalized costs to be presented in O&M Expense. In addition, the standard also adds presentation requirements for these costs in the statements of cash flows and financial position. The standard is effective for annual and interim periods beginning after December 15, 2019. Early adoption is permitted, including adoption in any interim period. This standard should be applied either retrospectively or prospectively to all implementation costs incurred after the date of adoption. PSEG is currently analyzing the impact of this standard on its financial statements. Targeted Improvements to Related Party Guidance for Variable Interest Entities (VIE) — ASU 2018-17 This accounting standard improves the VIE guidance in the area of decision-making fees. Consistent with how indirect interests held through related parties under common control are considered for determining whether a reporting entity must consolidate a VIE, indirect interests held through related parties in common control arrangements should be considered on a proportional basis for determining whether fees paid to decision makers and service providers are variable interests. This standard is effective for annual and interim periods beginning after December 15, 2019. The standard is required to be applied retrospectively with a cumulative-effect adjustment to retained earnings at the beginning of the earliest period presented. Early adoption is permitted. PSEG is currently analyzing the impact of this standard on 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 does not expect adoption of this standard to have a material impact on its financial statements. Disclosure Framework — Changes to the Disclosure Requirements for Defined Benefit Plans — ASU 2018-14 This accounting standard modifies the disclosure requirements for employers that sponsor defined benefit pension or other postretirement plans, including the elimination of certain current disclosure requirements. Certain other disclosure requirements related to interest crediting rates have been added and certain clarifications were made to other disclosure requirements. The standard is effective for fiscal years ending after December 15, 2020 and early adoption is permitted. An entity should apply the amendments in this standard on a retrospective basis to all periods presented. PSEG is currently analyzing the impact of this standard on its financial statements.
PSE&G [Member]
Accounting Policies
Revenue Recognition	Revenues from Contracts with Customers Electric and Gas Distribution and Transmission Revenues —PSE&G sells gas and electricity to customers under default commodity supply tariffs. PSE&G’s regulated electric and gas default commodity supply and distribution services are separate tariffs which are satisfied as the product(s) and/or services are delivered to the customer. The electric and gas commodity and delivery tariffs are recurring contracts in effect until cancellation by the customer. Revenue is recognized over time as the service is rendered to the customer. Included in PSE&G’s regulated revenues are unbilled electric and gas revenues which represent the estimated amount customers will be billed for services rendered from the most recent meter reading to the end of the respective accounting period. PSE&G’s transmission revenues are earned under a separate FERC tariff. The performance obligation of transmission service is satisfied over time as it is provided to and consumed by the 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 true-up mechanism is an alternative revenue which is outside the scope of revenue from contracts with customers. Other Revenues from Contracts with Customers Other revenues from contracts with customers, which are not a material source of PSE&G revenues, are generated primarily from appliance repair services and solar generation projects. The performance obligations under these contracts are satisfied and revenue is recognized as control of products is delivered or services are rendered. Payment for services rendered and products transferred are typically due within 30 days of month of delivery. Revenues Unrelated to Contracts with Customers Other PSE&G revenues unrelated to contracts with customers are derived from alternative revenue mechanisms recorded pursuant to regulatory accounting guidance. These revenues, which include weather normalization, green energy program true-ups and transmission formula rate true-ups, are not a material source of PSE&G revenues.
Power [Member]
Accounting Policies
Revenue Recognition	Revenues from Contracts with Customers 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, remains in effect 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. Other Revenues from Contracts with Customers 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. Revenues Unrelated to Contracts with Customers Power’s revenues unrelated to contracts with customers include electric, gas and certain energy-related transactions accounted for in accordance with Derivatives and Hedging accounting guidance. See Note 17. Financial Risk Management Activities for further discussion. Power is also a party to solar contracts that qualify as leases and are accounted for in accordance with lease accounting guidance.
Other [Member]
Accounting Policies
Revenue Recognition	Revenues from Contracts with Customers PSEG LI has a contract with LIPA which generates revenues. PSEG LI’s subsidiary, Servco records costs which are recovered from LIPA and records the recovery of those costs as revenues when Servco is a principal in the transaction. Revenues Unrelated to Contracts with Customers Energy Holdings generates lease revenues which are recorded pursuant to lease accounting guidance.

Organization, Basis Of Presen_3

Organization, Basis Of Presentation And Summary Of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2018
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Cash, Cash Equivalents and Restricted Cash	The following provides a reconciliation of cash, cash equivalents and restricted cash reported within the Consolidated Balance Sheets that sum to the total of the same such amounts for the beginning ( December 31, 2017 ) and ending periods shown in the Consolidated Statements of Cash Flows for the year ended December 31, 2018 . PSE&G Power Other (A) Consolidated Millions As of December 31, 2017 Cash and Cash Equivalents $ 242 $ 32 $ 39 $ 313 Restricted Cash in Other Current Assets — — — — Restricted Cash in Other Noncurrent Assets 2 — — 2 Cash, Cash Equivalents and Restricted Cash $ 244 $ 32 $ 39 $ 315 As of December 31, 2018 Cash and Cash Equivalents $ 39 $ 22 $ 116 $ 177 Restricted Cash in Other Current Assets 8 — — 8 Restricted Cash in Other Noncurrent Assets 14 — — 14 Cash, Cash Equivalents and Restricted Cash $ 61 $ 22 $ 116 $ 199 (A) Includes amounts applicable to PSEG (parent corporation), Energy Holdings and Services.
Depreciation Rate Stated Percentage	PSE&G calculates depreciation under the straight-line method based on estimated average remaining lives of the several classes of depreciable property. These estimates are reviewed on a periodic basis and necessary adjustments are made as approved by the BPU or FERC. The depreciation rate stated as a percentage of original cost of depreciable property was as follows: 2018 2017 2016 Avg Rate Avg Rate Avg Rate Electric Transmission 2.42 % 2.41 % 2.39 % Electric Distribution 2.51 % 2.51 % 2.49 % Gas Distribution 1.61 % 1.63 % 1.63 % Power calculates depreciation on generation-related assets under the straight-line method based on the assets’ estimated useful lives. The estimated useful lives are: • general plant assets— 3 years to 20 years • fossil production assets— 30 years to 67 years • nuclear generation assets—approximately 60 years • pumped storage facilities— 76 years • solar assets— 25 years
Amounts And Average Rates Used To Calculate IDC Or AFUDC	The amounts and average rates used to calculate AFUDC or IDC for the years ended December 31, 2018 , 2017 and 2016 were as follows: AFUDC/IDC Capitalized 2018 2017 2016 Millions Avg Rate Millions Avg Rate Millions Avg Rate PSE&G $ 70 7.74 % $ 73 7.42 % $ 66 7.81 % Power $ 67 4.60 % $ 78 4.60 % $ 54 4.87 %

Revenues Revenues (Tables)

Revenues Revenues (Tables)	12 Months Ended
	Dec. 31, 2018
Revenues [Abstract]
Disaggregation of Revenue [Table Text Block]	Disaggregation of Revenues PSE&G Power Other Eliminations Consolidated Millions Year Ended December 31, 2018 Revenues from Contracts with Customers Electric Distribution $ 3,131 $ — $ — $ — $ 3,131 Gas Distribution 1,756 — — (18 ) 1,738 Transmission 1,236 — — — 1,236 Electricity and Related Product Sales PJM Third Party Sales — 1,933 — — 1,933 Sales to Affiliates — 609 — (609 ) — New York ISO — 209 — — 209 ISO New England — 92 — — 92 Gas Sales Third Party Sales — 151 — — 151 Sales to Affiliates — 861 — (861 ) — Other Revenues from Contracts with Customers (A) 275 44 532 (4 ) 847 Total Revenues from Contracts with Customers 6,398 3,899 532 (1,492 ) 9,337 Revenues Unrelated to Contracts with Customers (B) 73 247 39 — 359 Total Operating Revenues $ 6,471 $ 4,146 $ 571 $ (1,492 ) $ 9,696 PSE&G Power Other Eliminations Consolidated Millions Year Ended December 31, 2017 Revenues from Contracts with Customers Electric Distribution $ 3,088 $ — $ — $ — $ 3,088 Gas Distribution 1,684 — — (14 ) 1,670 Transmission 1,222 — — — 1,222 Electricity and Related Product Sales PJM Third Party Sales — 1,199 — — 1,199 Sales to Affiliates — 734 — (734 ) — New York ISO — 181 — — 181 ISO New England — 39 — — 39 Gas Sales Third Party Sales — 134 — — 134 Sales to Affiliates — 804 — (804 ) — Other Revenues from Contracts with Customers (A) 265 42 511 (4 ) 814 Total Revenues from Contracts with Customers 6,259 3,133 511 (1,556 ) 8,347 Revenues Unrelated to Contracts with Customers (B) 65 727 (45 ) — 747 Total Operating Revenues $ 6,324 $ 3,860 $ 466 $ (1,556 ) $ 9,094 PSE&G Power Other Eliminations Consolidated Millions Year Ended December 31, 2016 Revenues from Contracts with Customers Electric Distribution $ 3,327 $ — $ — $ — $ 3,327 Gas Distribution 1,582 — — (22 ) 1,560 Transmission 1,084 — — — 1,084 Electricity and Related Product Sales PJM Third Party Sales — 1,060 — — 1,060 Sales to Affiliates — 805 — (805 ) — New York ISO — 169 — — 169 ISO New England — 55 — — 55 Gas Sales Third Party Sales — 114 — — 114 Sales to Affiliates — 737 — (737 ) — Other Revenues from Contracts with Customers (A) 292 35 482 (4 ) 805 Total Revenues from Contracts with Customers 6,285 2,975 482 (1,568 ) 8,174 Revenues Unrelated to Contracts with Customers (B) 18 886 (112 ) — 792 Total Operating Revenues $ 6,303 $ 3,861 $ 370 $ (1,568 ) $ 8,966 (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 years ended December 31, 2018 , 2017 and 2016 , Other includes losses of $8 million , $77 million and $147 million , respectively, related to Energy Holdings’ investments in leases. For additional information, see Note 8. Long-Term Investments .
Revenue, Capacity Auction Obligations [Table Text Block]	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 satisfied resulting from the base and incremental auctions which have been completed: 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 Capacity Payments from the New England ISO Forward Capacity Market —The Forward Capacity Market (FCM) Auction is conducted annually three years in advance of the operating period. The table below includes Power’s cleared capacity in the FCM Auction 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 Bridgeport Harbor Station 3 in 2021. Power expects to realize the following average capacity prices for capacity obligations to be satisfied resulting from the FCM auctions which have been completed: Delivery Year $ per MW-Day MW Cleared June 2018 to May 2019 $314 820 June 2019 to May 2020 $231 1,330 June 2020 to May 2021 $195 1,330 June 2021 to May 2022 $192 950 June 2022 to May 2023 $231 480 June 2023 to May 2024 $231 480 June 2024 to May 2025 $231 480 June 2025 to May 2026 $231 480 Bilateral capacity contracts —Capacity obligations pursuant to contract terms through 2029 are anticipated to result in revenues totaling $170 million .

Early Plant Retirements Early_2

Early Plant Retirements Early Plant Retirements (Tables)	12 Months Ended
	Dec. 31, 2018
Power [Member]
Restructuring Cost and Reserve [Line Items]
Property, Plant and Equipment [Table Text Block]	The following table provides the balance sheet amounts by generating station as of December 31, 2018 for significant assets and liabilities associated with Power’s owned share of its nuclear assets. As of December 31, 2018 Hope Creek Salem Support Facilities and Other (A) Peach Bottom Millions Assets Materials and Supplies Inventory $ 84 $ 65 $ — $ 41 Nuclear Production, net of Accumulated Depreciation 635 626 197 777 Nuclear Fuel In-Service, net of Accumulated Depreciation 139 110 — 148 Construction Work in Progress (including nuclear fuel) 131 132 5 20 Total Assets $ 989 $ 933 $ 202 $ 986 Liabilities Asset Retirement Obligation $ 253 $ 240 $ — $ 215 Total Liabilities $ 253 $ 240 $ — $ 215 Net Assets $ 736 $ 693 $ 202 $ 771 NRC License Renewal Term 2046 2036/2040 N/A 2033/2034 % Owned 100 % 57 % Various 50 % (A) Includes Hope Creek’s and Salem’s shared support facilities and other nuclear development capital.

Property, Plant And Equipment_2

Property, Plant And Equipment And Jointly-Owned Facilities (Tables)	12 Months Ended
	Dec. 31, 2018
Property, Plant and Equipment [Abstract]
Schedule Of Property, Plant And Equipment	Information related to Property, Plant and Equipment as of December 31, 2018 and 2017 is detailed below: PSE&G Power Other PSEG Consolidated Millions 2018 Transmission and Distribution: Electric Transmission $ 11,991 $ — $ — $ 11,991 Electric Distribution 8,989 — — 8,989 Gas Distribution and Transmission 7,854 — — 7,854 Construction Work in Progress 1,170 — — 1,170 Other 624 — — 624 Total Transmission and Distribution 30,628 — — 30,628 Generation: Fossil Production — 6,541 — 6,541 Nuclear Production — 2,971 — 2,971 Nuclear Fuel in Service — 765 — 765 Other Production-Solar 623 833 — 1,456 Construction Work in Progress — 1,011 — 1,011 Total Generation 623 12,121 — 12,744 Other 382 103 344 829 Total $ 31,633 $ 12,224 $ 344 $ 44,201 PSE&G Power Other PSEG Consolidated Millions 2017 Transmission and Distribution: Electric Transmission $ 10,425 $ — $ — $ 10,425 Electric Distribution 8,455 — — 8,455 Gas Distribution and Transmission 7,122 — — 7,122 Construction Work in Progress 1,735 — — 1,735 Other 512 — — 512 Total Transmission and Distribution 28,249 — — 28,249 Generation: Fossil Production — 4,923 — 4,923 Nuclear Production — 2,893 — 2,893 Nuclear Fuel in Service — 745 — 745 Other Production-Solar 593 757 — 1,350 Construction Work in Progress — 2,339 — 2,339 Total Generation 593 11,657 — 12,250 Other 275 98 359 732 Total $ 29,117 $ 11,755 $ 359 $ 41,231
Schedule Of Jointly-Owned Facilities	As of December 31, 2018 2017 Ownership Accumulated Accumulated Interest Plant Depreciation Plant Depreciation Millions PSE&G: Transmission Facilities Various $ 162 $ 58 $ 162 $ 58 Power: Coal Generating: Conemaugh 23 % $ 417 $ 192 $ 408 $ 178 Keystone 23 % $ 416 $ 200 $ 409 $ 187 Nuclear Generating: Peach Bottom 50 % $ 1,334 $ 389 $ 1,328 $ 348 Salem 57 % $ 1,196 $ 333 $ 1,147 $ 277 Nuclear Support Facilities Various $ 244 $ 95 $ 239 $ 81 Pumped Storage Facilities: Yards Creek 50 % $ 48 $ 26 $ 44 $ 26 Merrill Creek Reservoir 14 % $ 1 $ — $ 1 $ — Power holds undivided ownership interests in the jointly-owned facilities above.

Regulatory Assets And Liabili_2

Regulatory Assets And Liabilities (Tables)	12 Months Ended
	Dec. 31, 2018
Regulatory Assets and Liabilities Disclosure [Abstract]
Schedule of Regulatory Assets	PSE&G had the following Regulatory Assets and Liabilities: As of December 31, 2018 2017 Millions Regulatory Assets Current New Jersey Clean Energy Program $ 143 $ 128 Electric Energy Costs—Basic Generation Service (BGS) 115 23 Storm Damage and Other 56 — Green Program Recovery Charges (GPRC) 34 8 Weather Normalization Clause (WNC) 2 40 Other 39 12 Total Current Regulatory Assets $ 389 $ 211 Noncurrent Pension and OPEB Costs $ 1,090 $ 1,488 Deferred Income Tax Regulatory Assets 896 282 Manufactured Gas Plant (MGP) Remediation Costs 321 358 Electric Transmission and Gas Cost of Removal 223 199 Storm Damage and Other 214 241 Remediation Adjustment Charge (RAC) (Other Societal Benefits Charge (SBC)) 175 172 Asset Retirement Obligation 166 162 GPRC 95 98 Unamortized Loss on Reacquired Debt and Debt Expense 49 55 Gas Costs—BGSS 31 30 Other 139 137 Total Noncurrent Regulatory Assets $ 3,399 $ 3,222 Total Regulatory Assets $ 3,788 $ 3,433
Schedule of Regulatory Liabilities	As of December 31, 2018 2017 Millions Regulatory Liabilities Current Deferred Income Tax Regulatory Liabilities $ 299 $ — Gas Costs —BGSS — 30 Gas Margin Adjustment Clause 8 12 Other 4 5 Total Current Regulatory Liabilities $ 311 $ 47 Noncurrent Deferred Income Tax Regulatory Liabilities $ 3,170 $ 2,868 Electric Distribution Cost of Removal 51 80 Total Noncurrent Regulatory Liabilities $ 3,221 $ 2,948 Total Regulatory Liabilities $ 3,532 $ 2,995

Long-Term Investments (Tables)

Long-Term Investments (Tables)	12 Months Ended
	Dec. 31, 2018
Long-term Investments [Abstract]
Schedule of Long Term Investments	Long-Term Investments as of December 31, 2018 and 2017 included the following: As of December 31, 2018 2017 Millions PSE&G Life Insurance and Supplemental Benefits $ 121 $ 130 Solar Loans 149 150 Power Partnerships and Corporate Joint Ventures (Equity Method Investments) (A) 86 87 Energy Holdings Lease Investments 540 565 Total Long-Term Investments $ 896 $ 932 (A) During the three years ended December 31, 2018 , 2017 and 2016 , dividends from these investments were $16 million , $18 million and $18 million , respectively.
Schedule Of Net Investment In Leveraged Leases	The following table shows Energy Holdings’ gross and net lease investment as of December 31, 2018 and 2017 . As of December 31, 2018 2017 Millions Lease Receivables (net of Non-Recourse Debt) $ 504 $ 546 Estimated Residual Value of Leased Assets 326 326 Total Investment in Rental Receivables 830 872 Unearned and Deferred Income (290 ) (307 ) Gross Investments in Leases 540 565 Deferred Tax Liabilities (354 ) (480 ) Net Investments in Leases $ 186 $ 85
Schedule Of Pre-Tax Income And Income Tax Effects Related To Investments In Leveraged Leases	The pre-tax income (loss) and income tax effects related to investments in leases, excluding gains and losses on sales and the impacts of the Tax Act, were as follows: Years Ended December 31, 2018 2017 2016 Millions Pre-Tax Income (Loss) from Leases $ 17 $ (69 ) $ (135 ) Income Tax Expense (Benefit) on Income from Leases $ 6 $ (26 ) $ (51 )
Equity Method Investments	Equity Method Investments Power had the following equity method investments as of December 31, 2018 and 2017 : As of December 31, Name 2018 2017 Location % Owned Millions Power Keystone Fuels, LLC $ 9 $ 8 PA 23% Conemaugh Fuels, LLC 8 8 PA 23% Kalaeloa 69 71 HI 50% Total $ 86 $ 87

Financing Receivables (Tables)

Financing Receivables (Tables)	12 Months Ended
	Dec. 31, 2018
PSE&G [Member]
Financing Receivable, Recorded Investment [Line Items]
Schedule Of Credit Risk Profile Based On Payment Activity	The following table reflects the outstanding loans by class of customer, none of which would be considered “non-performing.” Outstanding Loans by Class of Customer As of December 31, Consumer Loans 2018 2017 Millions Commercial/Industrial $ 164 $ 158 Residential 9 10 Total $ 173 $ 168 Current Portion (included in Other Current Assets) (24 ) (18 ) Noncurrent Portion (included in Long-Term Investments) $ 149 $ 150
Energy Holdings [Member]
Financing Receivable, Recorded Investment [Line Items]
Schedule Of Lease Receivables, Net Of Nonrecourse Debt, Associated With Leveraged Lease Portfolio Based On Counterparty Credit Rating	The corresponding receivables associated with the lease portfolio are reflected as follows, net of non-recourse debt. The ratings in the table represent the ratings of the entities providing payment assurance to Energy Holdings. Lease Receivables, Net of Non-Recourse Debt Counterparties’ Credit Rating Standard & Poor’s (S&P) as of December 31, 2018 As of December 31, 2018 Millions AA $ 14 BBB+ — BBB- 316 BB 133 NR 41 Total $ 504
Schedule Of Assets Under Lease Receivables	The “ BB ” and the “ NR ” ratings in the preceding table represent lease receivables related to coal and gas-fired assets in Illinois and Pennsylvania, respectively. As of December 31, 2018 , the gross investment in the leases of such assets, net of non-recourse debt, was $296 million ( $10 million , net of deferred taxes). A more detailed description of such assets under lease follows: Asset Location Gross Investment % Owned Total MW Fuel Type Counterparties’ S&P Credit Ratings Counterparty Millions Powerton Station Units 5 and 6 IL $ 133 64 % 1,538 Coal BB NRG Energy, Inc. Joliet Station Units 7 and 8 IL $ 85 64 % 1,036 Gas BB NRG Energy, Inc. Shawville Station Units 1, 2, 3 and 4 PA $ 78 100 % 596 Gas NR REMA (A) (A) REMA emerged from Chapter 11 of the U.S. Bankruptcy Code in December 2018. For additional information, see Note 8. Long-Term Investments .

Trust Investments (Tables)

Trust Investments (Tables)	12 Months Ended
	Dec. 31, 2018
Nuclear Decommissioning Trust (NDT) Fund [Member]
Schedule of Trust Investments [Line Items]
Schedule of Available-for-sale Securities Reconciliation	The following tables show the fair values and gross unrealized gains and losses for the securities held in the NDT Fund. As of December 31, 2018 Cost Gross Unrealized Gains Gross Unrealized Losses Fair Value Millions Equity Securities Domestic $ 447 $ 153 $ (29 ) $ 571 International 323 36 (30 ) 329 Total Equity Securities 770 189 (59 ) 900 Available-for Sale Debt Securities Government 498 2 (9 ) 491 Corporate 501 1 (15 ) 487 Total Available-for-Sale Debt Securities 999 3 (24 ) 978 Total NDT Fund Investments $ 1,769 $ 192 $ (83 ) $ 1,878 As of December 31, 2017 Cost Gross Unrealized Gains Gross Unrealized Losses Fair Value Millions Equity Securities Domestic $ 497 $ 245 $ (2 ) $ 740 International 311 99 — (3 ) 407 Total Equity Securities 808 344 (5 ) 1,147 Available-for Sale Debt Securities Government 586 2 (4 ) 584 Corporate 400 4 (2 ) 402 Total Available-for-Sale Debt Securities 986 6 (6 ) 986 Total NDT Fund Investments $ 1,794 $ 350 $ (11 ) $ 2,133
Schedule Of Accounts Receivable And Accounts Payable	The amounts in the preceding tables do not include receivables and payables for NDT Fund transactions which have not settled at the end of each period. Such amounts are included in Accounts Receivable and Accounts Payable on the Consolidated Balance Sheets as shown in the following table. As of December 31, 2018 As of December 31, 2017 Millions Accounts Receivable $ 17 $ 24 Accounts Payable $ 5 $ 74
Value Of Securities That Have Been In An Unrealized Loss Position For Less Than And Greater Than 12 Months	The following table shows the value of securities in the NDT Fund that have been in an unrealized loss position for less than and greater than 12 months. As of December 31, 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 Equity Securities (A) Domestic $ 147 $ (26 ) $ 5 $ (3 ) $ 40 $ (2 ) $ — $ — International 131 (28 ) 5 (2 ) 29 (3 ) 2 — Total Equity Securities 278 (54 ) 10 (5 ) 69 (5 ) 2 — Available-for-Sale Debt Securities Government (B) 51 — 317 (9 ) 343 (2 ) 91 (2 ) Corporate (C) 150 (5 ) 222 (10 ) 191 (1 ) 27 (1 ) Total Available-for-Sale Debt Securities 201 (5 ) 539 (19 ) 534 (3 ) 118 (3 ) NDT Trust Investments $ 479 $ (59 ) $ 549 $ (24 ) $ 603 $ (8 ) $ 120 $ (3 ) (A) Equity Securities—Investments in marketable equity securities within the NDT Fund are primarily in common stocks within a broad range of industries and sectors. Effective January 1, 2018, unrealized gains and losses on these securities are recorded in Net Income. (B) Debt Securities (Government)—Unrealized gains and losses on these securities are recorded in Accumulated Other Comprehensive Income (Loss). The unrealized losses on Power’s NDT investments in U.S. Treasury obligations and Federal Agency mortgage-backed securities were caused by interest rate changes. These investments are guaranteed by the U.S. government or an agency of the U.S. government. Power also has investments in municipal bonds that are primarily in investment grade securities. It is not expected that these securities will settle for less than their amortized cost. Since Power does not intend to sell these securities nor will it be more-likely-than-not required to sell, Power does not consider these debt securities to be other-than-temporarily impaired as of December 31, 2018 . (C) Debt Securities (Corporate)—Unrealized gains and losses on these securities are recorded in Accumulated Other Comprehensive Income (Loss). Power’s investments in corporate bonds are primarily in investment grade securities. It is not expected that these securities would settle for less than their amortized cost. Since Power does not intend to sell these securities nor will it be more-likely-than-not required to sell, Power does not consider these debt securities to be other-than-temporarily impaired as of December 31, 2018 .
Amount Of Available-For-Sale Debt Securities By Maturity Periods	The NDT Fund debt securities held as of December 31, 2018 had the following maturities: Time Frame Fair Value Millions Less than one year $ 13 1 - 5 years 254 6 - 10 years 211 11 - 15 years 40 16 - 20 years 77 Over 20 years 383 Total NDT Available-for-Sale Debt Securities $ 978
Schedule of Realized Gain (Loss)	The proceeds from the sales of and the net gains (losses) on securities in the NDT Fund were: Years Ended December 31, 2018 2017 2016 Millions Proceeds from Sales (A) $ 1,398 $ 2,137 $ 711 Net Realized Gains (Losses): Gross Realized Gains $ 121 $ 157 $ 53 Gross Realized Losses (51 ) (23 ) (32 ) Net Realized Gains (Losses) on NDT Fund (B) $ 70 $ 134 $ 21 Unrealized Gains (Losses) on Equity Securities in NDT Fund (C) (209 ) N/A N/A Other-Than-Temporary-Impairments (OTTI) — (12 ) (28 ) Net Gains (Losses) on NDT Fund Investments $ (139 ) $ 122 $ (7 ) (A) Includes activity in accounts related to the liquidation of funds being transitioned to new managers. (B) The cost of these securities was determined on the basis of specific identification.
Rabbi Trust [Member]
Schedule of Trust Investments [Line Items]
Schedule of Available-for-sale Securities Reconciliation	As of December 31, 2018 Cost Gross Unrealized Gains Gross Unrealized Losses Fair Value Millions Equity Securities Domestic $ 22 $ 1 $ — $ 23 International — — — — Total Equity Securities 22 1 — 23 Available-for-Sale Debt Securities Government 110 1 (2 ) 109 Corporate 96 — (4 ) 92 Total Available-for-Sale Debt Securities 206 1 (6 ) 201 Total Rabbi Trust Investments $ 228 $ 2 $ (6 ) $ 224 As of December 31, 2017 Cost Gross Unrealized Gains Gross Unrealized Losses Fair Value Millions Equity Securities Domestic $ 24 $ 3 $ — $ 27 International — — — — Total Equity Securities 24 3 — 27 Available-for-Sale Debt Securities Government 85 1 (1 ) 85 Corporate 118 2 (1 ) 119 Total Available-for-Sale Debt Securities 203 3 (2 ) 204 Total Rabbi Trust Investments $ 227 $ 6 $ (2 ) $ 231
Schedule Of Accounts Receivable And Accounts Payable	The amounts in the preceding tables do not include receivables and payables for Rabbi Trust Fund transactions which have not settled at the end of each period. Such amounts are included in Accounts Receivable and Accounts Payable on the Consolidated Balance Sheets as shown in the following table. As of December 31, 2018 As of December 31, 2017 Millions Accounts Receivable $ 2 $ 2 Accounts Payable $ — $ 1
Value Of Securities That Have Been In An Unrealized Loss Position For Less Than And Greater Than 12 Months	The following table shows the value of securities in the Rabbi Trust Fund that have been in an unrealized loss position for less than and greater than 12 months: As of December 31, 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) $ 18 $ — $ 59 $ (2 ) $ 28 $ — $ 25 $ (1 ) Corporate (B) 50 (3 ) 29 (1 ) 39 (1 ) 9 — Total Available-for-Sale Debt Securities 68 (3 ) 88 (3 ) 67 (1 ) 34 (1 ) Rabbi Trust Investments $ 68 $ (3 ) $ 88 $ (3 ) $ 67 $ (1 ) $ 34 $ (1 ) (A) Debt Securities (Government)—Unrealized gains and losses on these securities are recorded in Accumulated Other Comprehensive Income (Loss). The unrealized losses on PSEG’s Rabbi Trust investments in U.S. Treasury obligations and Federal Agency mortgage-backed securities were caused by interest rate changes. These investments are guaranteed by the U.S. government or an agency of the U.S. government. PSEG also has investments in municipal bonds that are primarily in investment grade securities. It is not expected that these securities will settle for less than their amortized cost. Since PSEG does not intend to sell these securities nor will it be more-likely-than-not required to sell, PSEG does not consider these debt securities to be other-than-temporarily impaired as of December 31, 2018 . (B) Debt Securities (Corporate)—Unrealized gains and losses on these securities are recorded in Accumulated Other Comprehensive Income (Loss). PSEG’s investments in corporate bonds are primarily in investment grade securities. It is not expected that these securities would settle for less than their amortized cost. Since PSEG does not intend to sell these securities nor will it be more-likely-than-not required to sell, PSEG does not consider these debt securities to be other-than-temporarily impaired as of December 31, 2018
Amount Of Available-For-Sale Debt Securities By Maturity Periods	The Rabbi Trust debt securities held as of December 31, 2018 had the following maturities: Time Frame Fair Value Millions Less than one year $ 1 1 - 5 years 35 6 - 10 years 27 11 - 15 years 8 16 - 20 years 21 Over 20 years 109 Total Rabbi Trust Available-for-Sale Debt Securities $ 201
Schedule of Realized Gain (Loss)	The proceeds from the sales of and the net gains (losses) on securities in the Rabbi Trust Fund were: Years Ended December 31, 2018 2017 2016 Millions Proceeds from Rabbi Trust Sales (A) $ 103 $ 182 $ 113 Net Realized Gains (Losses): Gross Realized Gains $ 2 $ 17 $ 6 Gross Realized Losses (4 ) (5 ) (5 ) Net Realized Gains (Losses) on Rabbi Trust (B) (2 ) 12 1 Unrealized Gains (Losses) on Equity Securities in Rabbi Trust (C) (2 ) N/A N/A Net Gains (Losses) on Rabbi Trust Investments $ (4 ) $ 12 $ 1 (A) Includes activity in accounts related to the liquidation of funds being transitioned to new managers. (B) The cost of these securities was determined on the basis of specific identification.
Rabbi Trust Fair Value by Company	The fair value of the Rabbi Trust related to PSEG, PSE&G and Power are detailed as follows: As of December 31, As of December 31, 2018 2017 Millions PSE&G $ 45 $ 46 Power 56 57 Other 123 128 Total Rabbi Trust Investments $ 224 $ 231

Goodwill And Other Intangibles

Goodwill And Other Intangibles (Tables)	12 Months Ended
	Dec. 31, 2018
Power [Member]
Goodwill [Line Items]
Schedule of Intangibles	The changes to Power’s intangible assets during 2017 and 2018 are presented in the following table: Emissions Allowances RECs Total Other Intangibles Millions Balance as of January 1, 2017 $ 54 $ 44 $ 98 Retirements (7 ) (93 ) (100 ) Purchases 27 90 117 Sales and Transfers, net — (1 ) (1 ) Balance as of December 31, 2017 $ 74 $ 40 $ 114 Retirements (26 ) (90 ) (116 ) Purchases 36 110 146 Sales and Transfers, net — (1 ) (1 ) Balance as of December 31, 2018 $ 84 $ 59 $ 143

Asset Retirement Obligations _2

Asset Retirement Obligations (AROs) (Tables)	12 Months Ended
	Dec. 31, 2018
Asset Retirement Obligation [Abstract]
Impact Of The Revisions On Asset Retirement Obligation	The changes to the ARO liabilities for PSEG, PSE&G and Power during 2017 and 2018 are presented in the following table: PSEG PSE&G Power Other Millions ARO Liability as of January 1, 2017 $ 726 $ 213 $ 511 $ 2 Liabilities Settled (29 ) (8 ) (21 ) — Liabilities Incurred 1 — 1 — Accretion Expense 30 — 30 — Accretion Expense Deferred and Recovered in Rate Base (A) 12 12 — — Revision to Present Values of Estimated Cash Flows 284 (5 ) 289 — ARO Liability as of December 31, 2017 $ 1,024 $ 212 $ 810 $ 2 Liabilities Settled (10 ) (9 ) (1 ) — Liabilities Incurred 1 — 1 — Accretion Expense 41 — 41 — Accretion Expense Deferred and Recovered in Rate Base (A) 12 12 — — Revision to Present Values of Estimated Cash Flows (5 ) 87 (93 ) 1 ARO Liability as of December 31, 2018 $ 1,063 $ 302 $ 758 $ 3 (A) Not reflected as expense in Consolidated Statements of Operations

Pension, OPEB and Savings Pla_2

Pension, OPEB and Savings Plans (Tables)	12 Months Ended
	Dec. 31, 2018
Defined Benefit Plan [Abstract]
Schedule of Defined Benefit Plans Disclosures	The following table provides a roll-forward of the changes in Servco’s benefit obligation and the fair value of its plan assets during the years ended December 31, 2018 and 2017 . It also provides the funded status of the plans and the amounts recognized and amounts not recognized on the Consolidated Balance Sheets at the end of both years. Pension Benefits Other Benefits 2018 2017 2018 2017 Millions Change in Benefit Obligation Benefit Obligation at Beginning of Year $ 320 $ 262 $ 542 $ 452 Service Cost 30 27 18 15 Interest Cost 12 11 20 19 Actuarial (Gain) Loss (38 ) 22 (73 ) 60 Gross Benefits Paid (3 ) (2 ) (6 ) (4 ) Plan Amendments — — — — Benefit Obligation at End of Year (A) $ 321 $ 320 $ 501 $ 542 Change in Plan Assets Fair Value of Assets at Beginning of Year $ 191 $ 134 $ — $ — Actual Return on Plan Assets (16 ) 24 — — Employer Contributions 40 35 6 4 Gross Benefits Paid (3 ) (2 ) (6 ) (4 ) Fair Value of Assets at End of Year $ 212 $ 191 $ — $ — Funded Status Funded Status (Plan Assets less Benefit Obligation) $ (109 ) $ (129 ) $ (501 ) $ (542 ) Additional Amounts Recognized in the Consolidated Balance Sheets Accrued Pension Costs of Servco $ (109 ) $ (129 ) N/A N/A OPEB Costs of Servco N/A N/A (501 ) (542 ) Amounts Recognized (B) $ (109 ) $ (129 ) $ (501 ) $ (542 ) (A) Represents projected benefit obligation for pension benefits and the accumulated postretirement benefit obligation for other benefits. The vested benefit obligation is the actuarial present value of the vested benefits to which the employee is currently entitled but based on the employee’s expected date of separation of retirement. (B) Amounts equal to the accrued pension and OPEB costs of Servco are offset in Long-Term Receivable of VIE on PSEG’s Consolidated Balance Sheets. The following table provides a roll-forward of the changes in the benefit obligation and the fair value of plan assets during each of the two years in the periods ended December 31, 2018 and 2017 . It also provides the funded status of the plans and the amounts recognized and amounts not recognized on the Consolidated Balance Sheets at the end of both years. Pension Benefits Other Benefits 2018 2017 2018 2017 Millions Change in Benefit Obligation Benefit Obligation at Beginning of Year (A) $ 6,359 $ 5,772 $ 1,976 $ 1,754 Service Cost 130 114 18 17 Interest Cost 208 204 66 63 Actuarial (Gain) Loss (460 ) 564 (222 ) 199 Gross Benefits Paid (316 ) (295 ) (76 ) (57 ) Plan Amendments — — (559 ) — Benefit Obligation at End of Year (A) $ 5,921 $ 6,359 $ 1,203 $ 1,976 Change in Plan Assets Fair Value of Assets at Beginning of Year $ 5,812 $ 5,193 $ 511 $ 420 Actual Return on Plan Assets (388 ) 903 (36 ) 77 Employer Contributions 12 11 89 71 Gross Benefits Paid (316 ) (295 ) (76 ) (57 ) Fair Value of Assets at End of Year $ 5,120 $ 5,812 $ 488 $ 511 Funded Status Funded Status (Plan Assets less Benefit Obligation) $ (801 ) $ (547 ) $ (715 ) $ (1,465 ) Additional Amounts Recognized in the Consolidated Balance Sheets Current Accrued Benefit Cost (10 ) (10 ) (11 ) (10 ) Noncurrent Accrued Benefit Cost (791 ) (537 ) (704 ) (1,455 ) Amounts Recognized $ (801 ) $ (547 ) $ (715 ) $ (1,465 ) Additional Amounts Recognized in Accumulated Other Comprehensive Income (Loss), Regulated Assets and Deferred Assets (B) Prior Service Cost $ (28 ) $ (46 ) $ (561 ) $ (3 ) Net Actuarial Loss 2,005 1,721 420 629 Total $ 1,977 $ 1,675 $ (141 ) $ 626 (A) Represents projected benefit obligation for pension benefits and the accumulated postretirement benefit obligation for other benefits. The vested benefit obligation is the actuarial present value of the vested benefits to which the employee is currently entitled but based on the employee’s expected date of separation of retirement. (B) Includes $ 619 million ($ 360 million , after-tax) and $ 683 million ($ 406 million , after-tax) in Accumulated Other Comprehensive Loss related to Pension and OPEB as of December 31, 2018 and 2017 , respectively. Also includes Regulatory Assets of $1,090 million and Deferred Assets of $127 million as of December 31, 2018 and Regulatory Assets of $1,485 million and Deferred Assets of $133 million as of December 31, 2017 .
Components Of Net Periodic Benefit Cost	The following table provides the components of net periodic benefit cost relating to all qualified and nonqualified pension and OPEB plans on an aggregate basis for PSEG, excluding Servco for the years ended December 31, 2018 , 2017 and 2016 . Amounts shown do not reflect the impacts of capitalization and co-owner allocations. Effective with the adoption of ASU 2017-07 on January 1, 2018, only the service cost component is eligible for capitalization, when applicable. For additional information, see Note 2. Recent Accounting Standards . Pension Benefits Years Ended December 31, Other Benefits Years Ended December 31, 2018 2017 2016 2018 2017 2016 Millions Components of Net Periodic Benefit (Credits) Costs Service Cost (included in O&M Expense) $ 130 $ 114 $ 109 $ 18 $ 17 $ 17 Non-Service Components of Pension and OPEB (Credits) Costs Interest Cost 208 204 202 66 63 59 Expected Return on Plan Assets (441 ) (394 ) (394 ) (41 ) (34 ) (31 ) Amortization of Net Prior Service Credit (18 ) (18 ) (19 ) (1 ) (11 ) (14 ) Actuarial Loss 85 97 158 64 51 40 Non-Service Components of Pension and OPEB (Credits) Costs (166 ) (111 ) (53 ) 88 69 54 Total Benefit (Credits) Costs $ (36 ) $ 3 $ 56 $ 106 $ 86 $ 71
Schedule Of Pension And OPEB Costs	Pension costs and OPEB costs for PSEG, PSE&G and Power are detailed as follows: Pension Benefits Years Ended December 31, Other Benefits Years Ended December 31, 2018 2017 2016 2018 2017 2016 Millions PSE&G $ (31 ) $ (4 ) $ 29 $ 68 $ 54 $ 43 Power (9 ) 1 16 32 27 23 Other 4 6 11 6 5 5 Total Benefit (Credits) Costs $ (36 ) $ 3 $ 56 $ 106 $ 86 $ 71
Schedule of Amounts Recognized in Other Comprehensive Income (Loss)	The following table provides the pre-tax changes recognized in Accumulated Other Comprehensive Income (Loss), Regulatory Assets and Deferred Assets: Pension OPEB 2018 2017 2018 2017 Millions Net Actuarial (Gain) Loss in Current Period $ 369 $ 55 $ (145 ) $ 156 Amortization of Net Actuarial Gain (Loss) (85 ) (97 ) (64 ) (50 ) Prior Service Cost (Credit) in current period — — (559 ) — Amortization of Prior Service Credit 18 18 1 11 Total $ 302 $ (24 ) $ (767 ) $ 117
Schedule of Amounts in Accumulated Other Comprehensive Income (Loss) to be Recognized over Next Fiscal Year	Amounts that are expected to be amortized from Accumulated Other Comprehensive Loss, Regulatory Assets and Deferred Assets into Net Periodic Benefit Cost in 2019 are as follows: Pension Benefits Other Benefits 2019 2019 Millions Actuarial Loss $ 107 $ 50 Prior Service Credit $ (18 ) $ (128 )
Schedule of Assumptions Used	The following assumptions were used to determine the benefit obligations of Servco: Pension Benefits Other Benefits 2018 2017 2016 2018 2017 2016 Weighted-Average Assumptions Used to Determine Benefit Obligations as of December 31 Discount Rate 4.60 % 3.90 % 4.61 % 4.67 % 3.96 % 4.71 % Rate of Compensation Increase 3.25 % 3.25 % 3.25 % 3.25 % 3.25 % 3.25 % Assumed Health Care Cost Trend Rates as of December 31 Health Care Costs Immediate Rate 8.03 % 7.69 % 7.55 % Ultimate Rate 4.75 % 4.75 % 4.75 % Year Ultimate Rate Reached 2026 2026 2025 Millions Effect of a 1% Increase in the Assumed Rate of Increase in Health Care Benefit Costs Postretirement Benefit Obligation $ 108 $ 131 $ 97 Effect of a 1% Decrease in the Assumed Rate of Increase in Health Care Benefit Costs Postretirement Benefit Obligation $ (83 ) $ (99 ) $ (75 ) The following assumptions were used to determine the benefit obligations and net periodic benefit costs: Pension Benefits Other Benefits 2018 2017 2016 2018 2017 2016 Weighted-Average Assumptions Used to Determine Benefit Obligations as of December 31 Discount Rate 4.41 % 3.73 % 4.29 % 4.31 % 3.76 % 4.37 % Rate of Compensation Increase 3.90 % 3.90 % 3.61 % 3.90 % 3.90 % 3.61 % Weighted-Average Assumptions Used to Determine Net Periodic Benefit Cost for Years Ended December 31 Discount Rate 3.73 % 4.29 % 4.54 % 3.76 % 4.37 % 4.58 % Service Cost Interest Rate 3.88 % 4.53 % 4.81 % 3.90 % 4.64 % 4.87 % Interest Cost Interest Rate 3.35 % 3.63 % 3.75 % 3.39 % 3.69 % 3.76 % Expected Return on Plan Assets 7.80 % 7.80 % 8.00 % 7.80 % 7.80 % 8.00 % Rate of Compensation Increase 3.90 % 3.61 % 3.61 % 3.90 % 3.61 % 3.61 % Assumed Health Care Cost Trend Rates as of December 31 Health Care Costs Immediate Rate 7.28 % 7.93 % 7.55 % Ultimate Rate 4.75 % 4.75 % 4.75 % Year Ultimate Rate Reached 2026 2026 2025 Millions Effect of a 1% Increase in the Assumed Rate of Increase in Health Care Benefit Costs Total of Service Cost and Interest Cost $ 1 $ 13 $ 11 Postretirement Benefit Obligation $ 21 $ 240 $ 191 Effect of a 1% Decrease in the Assumed Rate of Increase in Health Care Benefit Costs Total of Service Cost and Interest Cost $ (1 ) $ (10 ) $ (9 ) Postretirement Benefit Obligation $ (20 ) $ (198 ) $ (160 )
Schedule of Allocation of Plan Assets	The following tables present information about Servco’s investments measured at fair value on a recurring basis as of December 31, 2018 and 2017 , including the fair value measurements and the levels of inputs used in determining those fair values. Recurring Fair Value Measurements as of December 31, 2018 Quoted Market Prices for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Description Total (Level 1) (Level 2) (Level 3) Millions Commingled Equities (A) $ 141 $ — $ 141 $ — Commingled Bonds (A) 71 — 71 — Total $ 212 $ — $ 212 $ — Recurring Fair Value Measurements as of December 31, 2017 Quoted Market Prices for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Description Total (Level 1) (Level 2) (Level 3) Millions Commingled Equities (A) $ 137 $ — $ 137 $ — Commingled Bonds (A) 54 — 54 — Total $ 191 $ — $ 191 $ — (A) Investments in commingled equity and bond funds have a readily determinable fair value as they publish a daily NAV available to investors which is the basis for current transactions and contain certain redemption restrictions requiring advance notice of one to two days for withdrawals (Level 2). The following tables present information about the investments measured at fair value on a recurring basis as of December 31, 2018 and 2017 , including the fair value measurements and the levels of inputs used in determining those fair values. Recurring Fair Value Measurements as of December 31, 2018 Quoted Market Prices for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Description Total (Level 1) (Level 2) (Level 3) Millions Cash Equivalents (A) $ 99 $ 88 $ 11 $ — Equity Securities Common Stock (B) 1,156 1,156 — — Commingled (C) 1,338 960 378 — Preferred Stock (B) 7 7 — — Other (D) 1 1 — — Debt Securities (E) U.S. Treasury 526 — 526 — Government—Other 302 — 302 — Corporate 948 — 948 — Subtotal Fair Value $ 4,377 $ 2,212 $ 2,165 $ — Measured at net asset value practical expedient Commingled—Equities (F) 1,208 Private Equity (G) 10 Total Fair Value (H) $ 5,595 Recurring Fair Value Measurements as of December 31, 2017 Quoted Market Prices for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Description Total (Level 1) (Level 2) (Level 3) Millions Cash Equivalents (A) $ 133 $ 117 $ 16 $ — Equity Securities Common Stock (B) 1,275 1,275 — — Commingled (C) 1,401 1,218 183 — Preferred Stock (B) 6 6 — — Debt Securities (E) U.S. Treasury 571 — 571 — Government—Other 272 — 272 — Corporate 963 — 963 — Subtotal Fair Value $ 4,621 $ 2,616 $ 2,005 $ — Measured at net asset value practical expedient Commingled—Equities (F) 1,675 Private Equity (G) 14 Total Fair Value (H) $ 6,310 (A) The Collective Investment Fund publishes a daily net asset value (NAV) which participants may use for daily redemptions without restrictions (Level 1). Certain temporary investments are valued using inputs such as time-to-maturity, coupon rate, quality rating and current yield (Level 2). (B) Common stocks and preferred stocks are measured using observable data in active markets and considered Level 1. (C) Commingled Funds that allow daily redemption at their daily published NAV without restrictions are classified as Level 1. Commingled Funds that publish daily NAV but with certain near-term redemption restrictions which prevent redemption at the published daily NAV are classified as Level 2. (D) Investment in a publicly traded limited partnership. (E) Debt securities include mainly investment grade corporate and municipal bonds, U.S. Treasury obligations and Federal Agency asset-backed securities with a wide range of maturities. These investments are valued using an evaluated pricing approach that varies by asset class and reflects observable market information such as the most recent exchange price or quoted bid for similar securities. Market-based standard inputs typically include benchmark yields, reported trades, broker/dealer quotes and issuer spreads or the most recent quotes for similar securities which are a Level 2 measure. (F) Certain commingled equity funds are not included in the fair value hierarchy as they are measured at fair value using the NAV per share (or its equivalent) practical expedient. These funds do not meet the definition of readily determinable fair value due to limitations in published NAV (last business day of the month) and include certain redemption restrictions ranging from one to fifteen days advance notice prior to redemption days and limitations on withdrawals over 25% of the total fund. The objectives of these funds are mainly tracking the S&P Index or achieving long-term growth through investment in foreign equity securities and the MSCI Emerging Markets Index. (G) Private equity investments primarily include various limited partnerships that invest in either operating companies through acquisitions or developing a portfolio of non-US distressed investments to maximize total return on capital. These investments are valued at NAV (or its equivalent) on an annual basis and have significant redemption restrictions preventing redemption until fund liquidation and limited ability to sell these investments. Fund liquidation is not expected to occur for several more years. These investments have been removed from the fair value hierarchy in accordance with the guidance on NAV practical expedient. (H) Excludes net receivables of $14 million and $13 million at December 31, 2018 and 2017 , respectively, which consist of interest, dividends and receivables and payables related to pending securities sales and purchases.
Schedule of Effect of Significant Unobservable Inputs, Changes in Plan Assets	The following tables present information about the investments measured at fair value on a recurring basis as of December 31, 2018 and 2017 , including the fair value measurements and the levels of inputs used in determining those fair values. Recurring Fair Value Measurements as of December 31, 2018 Quoted Market Prices for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Description Total (Level 1) (Level 2) (Level 3) Millions Cash Equivalents (A) $ 99 $ 88 $ 11 $ — Equity Securities Common Stock (B) 1,156 1,156 — — Commingled (C) 1,338 960 378 — Preferred Stock (B) 7 7 — — Other (D) 1 1 — — Debt Securities (E) U.S. Treasury 526 — 526 — Government—Other 302 — 302 — Corporate 948 — 948 — Subtotal Fair Value $ 4,377 $ 2,212 $ 2,165 $ — Measured at net asset value practical expedient Commingled—Equities (F) 1,208 Private Equity (G) 10 Total Fair Value (H) $ 5,595 Recurring Fair Value Measurements as of December 31, 2017 Quoted Market Prices for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Description Total (Level 1) (Level 2) (Level 3) Millions Cash Equivalents (A) $ 133 $ 117 $ 16 $ — Equity Securities Common Stock (B) 1,275 1,275 — — Commingled (C) 1,401 1,218 183 — Preferred Stock (B) 6 6 — — Debt Securities (E) U.S. Treasury 571 — 571 — Government—Other 272 — 272 — Corporate 963 — 963 — Subtotal Fair Value $ 4,621 $ 2,616 $ 2,005 $ — Measured at net asset value practical expedient Commingled—Equities (F) 1,675 Private Equity (G) 14 Total Fair Value (H) $ 6,310 (A) The Collective Investment Fund publishes a daily net asset value (NAV) which participants may use for daily redemptions without restrictions (Level 1). Certain temporary investments are valued using inputs such as time-to-maturity, coupon rate, quality rating and current yield (Level 2). (B) Common stocks and preferred stocks are measured using observable data in active markets and considered Level 1. (C) Commingled Funds that allow daily redemption at their daily published NAV without restrictions are classified as Level 1. Commingled Funds that publish daily NAV but with certain near-term redemption restrictions which prevent redemption at the published daily NAV are classified as Level 2. (D) Investment in a publicly traded limited partnership. (E) Debt securities include mainly investment grade corporate and municipal bonds, U.S. Treasury obligations and Federal Agency asset-backed securities with a wide range of maturities. These investments are valued using an evaluated pricing approach that varies by asset class and reflects observable market information such as the most recent exchange price or quoted bid for similar securities. Market-based standard inputs typically include benchmark yields, reported trades, broker/dealer quotes and issuer spreads or the most recent quotes for similar securities which are a Level 2 measure. (F) Certain commingled equity funds are not included in the fair value hierarchy as they are measured at fair value using the NAV per share (or its equivalent) practical expedient. These funds do not meet the definition of readily determinable fair value due to limitations in published NAV (last business day of the month) and include certain redemption restrictions ranging from one to fifteen days advance notice prior to redemption days and limitations on withdrawals over 25% of the total fund. The objectives of these funds are mainly tracking the S&P Index or achieving long-term growth through investment in foreign equity securities and the MSCI Emerging Markets Index. (G) Private equity investments primarily include various limited partnerships that invest in either operating companies through acquisitions or developing a portfolio of non-US distressed investments to maximize total return on capital. These investments are valued at NAV (or its equivalent) on an annual basis and have significant redemption restrictions preventing redemption until fund liquidation and limited ability to sell these investments. Fund liquidation is not expected to occur for several more years. These investments have been removed from the fair value hierarchy in accordance with the guidance on NAV practical expedient. (H) Excludes net receivables of $14 million and $13 million at December 31, 2018 and 2017 , respectively, which consist of interest, dividends and receivables and payables related to pending securities sales and purchases.
Schedule Of Percentage Of Fair Value Of Total Plan Assets	The following table provides the percentage of fair value of total plan assets for each major category of plan assets held for the qualified pension and OPEB plans of Servco as of the measurement date, December 31: As of December 31, Investments 2018 2017 Equity Securities 67 % 72 % Debt Securities 33 28 Total Percentage 100 % 100 % The following table provides the percentage of fair value of total plan assets for each major category of plan assets held for the qualified pension and OPEB plans as of the measurement date, December 31: As of December 31, Investments 2018 2017 Equity Securities 66 % 69 % Debt Securities 32 29 Other Investments 2 2 Total Percentage 100 % 100 %
Schedule of Expected Benefit Payments	The following pension benefit and postretirement benefit payments are expected to be paid to plan participants. Year Pension Benefits Other Benefits Millions 2019 $ 345 $ 91 2020 341 95 2021 352 87 2022 364 88 2023 373 89 2024-2028 2,004 428 Total $ 3,779 $ 878 The following pension benefit and postretirement benefit payments are expected to be paid to Servco’s plan participants: Year Pension Benefits Other Benefits Millions 2019 $ 4 $ 6 2020 6 8 2021 7 10 2022 9 12 2023 11 14 2024-2028 91 99 Total $ 128 $ 149
Schedule Of Amount Paid For Employer Matching Contributions	The amount paid for employer matching contributions to the plans for PSEG, PSE&G and Power are detailed as follows: Thrift Plan and Savings Plan Years Ended December 31, 2018 2017 2016 Millions PSE&G $ 26 $ 25 $ 24 Power 10 11 12 Other 5 5 5 Total Employer Matching Contributions $ 41 $ 41 $ 41

Commitments and Contingent Li_2

Commitments and Contingent Liabilities (Tables)	12 Months Ended
	Dec. 31, 2018
Other Commitments [Line Items]
Future Minimum Rental Payments	The total future minimum payments under various operating leases as of December 31, 2018 are: PSE&G Power Services Other Total Millions 2019 $ 15 $ 11 $ 14 $ 1 $ 41 2020 11 13 14 2 40 2021 10 13 15 1 39 2022 8 14 15 1 38 2023 8 8 15 — 31 Thereafter 66 51 105 — 222 Total Minimum Lease Payments $ 118 $ 110 $ 178 $ 5 $ 411
PSE&G [Member]
Other Commitments [Line Items]
Contract For Anticipated BGS-Fixed Price Eligible Load	The contract prices in dollars per MWh for the BGS-RSCP supply, as well as the approximate load, are as follows: Auction Year 2016 2017 2018 2019 36-Month Terms Ending May 2019 May 2020 May 2021 May 2022 (A) Load (MW) 2,800 2,800 2,900 2,800 $ per MWh $96.38 $90.78 $91.77 $98.04 (A) Prices set in the 2019 BGS auction will become effective on June 1, 2019 when the 2016 BGS auction agreements expire.
Power [Member]
Other Commitments [Line Items]
Face Value Of Outstanding Guarantees, Current Exposure And Margin Positions	The following table shows the face value of Power’s outstanding guarantees, current exposure and margin positions as of December 31, 2018 and 2017 . As of December 31, 2018 As of December 31, 2017 Millions Face Value of Outstanding Guarantees $ 1,772 $ 1,701 Exposure under Current Guarantees $ 198 $ 153 Letters of Credit Margin Posted $ 115 $ 103 Letters of Credit Margin Received $ 26 $ 32 Cash Deposited and Received Counterparty Cash Margin Deposited $ — $ — Counterparty Cash Margin Received $ (10 ) $ (1 ) Net Broker Balance Deposited (Received) $ 403 $ 147 Additional Amounts Posted Other Letters of Credit $ 52 $ 61
Total Minimum Purchase Commitments	As of December 31, 2018 , the total minimum purchase requirements included in these commitments were as follows: Fuel Type Power's Share of Commitments through 2023 Millions Nuclear Fuel Uranium $ 222 Enrichment $ 358 Fabrication $ 167 Natural Gas $ 1,102 Coal $ 429

Debt and Credit Facilities (Tab

Debt and Credit Facilities (Tables)	12 Months Ended
	Dec. 31, 2018
Debt Disclosure [Abstract]
Long-Term Debt	Long-Term Debt As of December 31, Maturity 2018 2017 Millions PSEG Term Loan: Variable 2019 $ 350 $ 700 Variable 2020 700 — Total Term Loan 1,050 700 Senior Notes: 1.60% 2019 400 400 2.00% 2021 300 300 2.65% 2022 700 700 Total Senior Notes 1,400 1,400 Principal Amount Outstanding 2,450 2,100 Amounts Due Within One Year (750 ) — Net Unamortized Discount and Debt Issuance Costs (7 ) (9 ) Total Long-Term Debt of PSEG $ 1,693 $ 2,091 ` As of December 31, Maturity 2018 2017 Millions PSE&G First and Refunding Mortgage Bonds (A): 9.25% 2021 $ 134 $ 134 8.00% 2037 7 7 5.00% 2037 8 8 Total First and Refunding Mortgage Bonds 149 149 Medium-Term Notes (MTNs) (A): 5.30% 2018 — 400 2.30% 2018 — 350 1.80% 2019 250 250 2.00% 2019 250 250 3.50% 2020 250 250 7.04% 2020 9 9 1.90% 2021 300 300 2.38% 2023 500 500 3.25% 2023 325 — 3.75% 2024 250 250 3.15% 2024 250 250 3.05% 2024 250 250 3.00% 2025 350 350 2.25% 2026 425 425 3.00% 2027 425 425 3.70% 2028 375 — 3.65% 2028 325 — 5.25% 2035 250 250 5.70% 2036 250 250 5.80% 2037 350 350 5.38% 2039 250 250 5.50% 2040 300 300 3.95% 2042 450 450 3.65% 2042 350 350 3.80% 2043 400 400 4.00% 2044 250 250 4.05% 2045 250 250 4.15% 2045 250 250 3.80% 2046 550 550 3.60% 2047 350 350 4.05% 2048 325 — Total MTNs 9,109 8,509 Principal Amount Outstanding 9,258 8,658 Amounts Due Within One Year (500 ) (750 ) Net Unamortized Discount and Debt Issuance Costs (74 ) (67 ) Total Long-Term Debt of PSE&G $ 8,684 $ 7,841 As of December 31, Maturity 2018 2017 Millions Power Senior Notes: 2.45% 2018 $ — $ 250 5.13% 2020 406 406 3.00% 2021 700 700 4.15% 2021 250 250 3.85% 2023 700 — 4.30% 2023 250 250 8.63% 2031 500 500 Total Senior Notes 2,806 2,356 Pollution Control Notes: Floating Rate (B) 2019 44 44 Total Pollution Control Notes 44 44 Principal Amount Outstanding 2,850 2,400 Amounts Due Within One Year (44 ) (250 ) Net Unamortized Discount and Debt Issuance Costs (15 ) (14 ) Total Long-Term Debt of Power $ 2,791 $ 2,136 (A) Secured by essentially all property of PSE&G pursuant to its First and Refunding Mortgage. (B) The Pennsylvania Economic Development Authority (PEDFA) bond that is serviced and secured by Power Pollution Control Notes is a variable rate bond that is in weekly reset mode.
Aggregate Principal Amounts Of Maturities	The aggregate principal amounts of maturities for each of the five years following December 31, 2018 are as follows: Year PSEG PSE&G Power Total 2019 $ 750 $ 500 $ 44 $ 1,294 2020 700 259 406 1,365 2021 300 434 950 1,684 2022 700 — — 700 2023 — 825 950 1,775 Thereafter — 7,240 500 7,740 Total $ 2,450 $ 9,258 $ 2,850 $ 14,558
Short-Term Liquidity	total credit facilities and available liquidity as of December 31, 2018 were as follows: As of December 31, 2018 Company/Facility Total Facility Usage Available Liquidity Expiration Date Primary Purpose Millions PSEG 5-year Credit Facilities (A) $ 1,500 $ 759 $ 741 Mar 2022 Commercial Paper Support/Funding/Letters of Credit Total PSEG $ 1,500 $ 759 $ 741 PSE&G 5-year Credit Facility (A) $ 600 $ 288 $ 312 Mar 2022 Commercial Paper Support/Funding/Letters of Credit Total PSE&G $ 600 $ 288 $ 312 Power 3-year Letter of Credit Facilities $ 200 $ 114 $ 86 Sept 2021 Letters of Credit 5-year Credit Facilities 1,900 40 1,860 Mar 2022 Funding/Letters of Credit Total Power $ 2,100 $ 154 $ 1,946 Total $ 4,200 $ 1,201 $ 2,999 (A) The primary use of PSEG’s and PSE&G’s credit facilities is to support their respective Commercial Paper Programs under which as of December 31, 2018 , PSEG had $744 million outstanding at a weighted average interest rate of 2.95% . PSE&G had $272 million outstanding at a weighted average interest rate of 2.96% under its Commercial Paper Program as of December 31, 2018 .
Estimated Fair Values	December 31, 2018 December 31, 2017 Carrying Amount Fair Value Carrying Amount Fair Value Millions Long-Term Debt: PSEG (A) (B) $ 2,443 $ 2,397 $ 2,091 $ 2,081 PSE&G (B) 9,184 9,374 8,591 9,322 Power (B) 2,835 2,996 2,386 2,659 Total Long-Term Debt $ 14,462 $ 14,767 $ 13,068 $ 14,062 (A) As of December 31, 2018 and 2017 , fair value includes floating rate term loans of $1,050 million and $700 million , respectively. The fair value of the term loan debt (Level 2 measurement) approximates the carrying value because the interest payments are based on LIBOR rates that are reset monthly and the debt is redeemable at face value by PSEG at any time. (B) Given that these bonds do not trade actively, the fair value amounts of taxable debt securities (primarily Level 2 measurements) are generally determined by a valuation model that is based on a conventional discounted cash flow methodology and utilizes assumptions of current market pricing curves. In order to incorporate the credit risk into the discount rates, pricing 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.

Schedule Of Consolidated Capi_2

Schedule Of Consolidated Capital Stock (Tables)	12 Months Ended
	Dec. 31, 2018
Class of Stock Disclosures [Abstract]
Schedule Of Consolidated Capital Stock	As of December 31, Outstanding Shares Book Value 2018 2017 2018 2017 Millions PSEG Common Stock (no par value) (A) Authorized 1,000 shares 504 505 $ 4,172 $ 4,198 (A) PSEG did not issue any new shares under the Dividend Reinvestment and Stock Purchase Plan (DRASPP) or the Employee Stock Purchase Plan (ESPP) in 2018 or 2017 .

Financial Risk Management Act_2

Financial Risk Management Activities (Tables)	12 Months Ended
	Dec. 31, 2018
Disclosure Financial Risk Management Activities [Abstract]
Schedule Of Derivative Instruments Fair Value In Balance Sheets	The following tabular disclosure does not include the offsetting of trade receivables and payables. As of December 31, 2018 Power (A) Consolidated Not Designated Balance Sheet Location Energy- Related Contracts Netting (B) Total Power Total Derivatives Millions Derivative Contracts Current Assets $ 426 $ (415 ) $ 11 $ 11 Noncurrent Assets 137 (136 ) 1 1 Total Mark-to-Market Derivative Assets $ 563 $ (551 ) $ 12 $ 12 Derivative Contracts Current Liabilities $ (521 ) $ 510 $ (11 ) $ (11 ) Noncurrent Liabilities (198 ) 194 (4 ) (4 ) Total Mark-to-Market Derivative (Liabilities) $ (719 ) $ 704 $ (15 ) $ (15 ) Total Net Mark-to-Market Derivative Assets (Liabilities) $ (156 ) $ 153 $ (3 ) $ (3 ) 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 derivative instruments are contracts subject to master netting agreements. Contracts not subject to master netting or similar agreements are immaterial and did not have any collateral posted or received as of December 31, 2018 and 2017 . PSE&G does not have any derivative contracts subject to master netting or similar agreements. (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 Consolidated Balance Sheets. As of December 31, 2018 and 2017 , Power had net cash collateral/margin payments to counterparties of $393 million and $146 million , respectively. Of these net cash collateral/margin payments, $153 million as of December 31, 2018 and $44 million as of December 31, 2017 were netted against the corresponding net derivative contract positions. Of the $153 million as of December 31, 2018 , $(2) million was netted against current assets, $(3) million was netted against noncurrent assets, $96 million was netted against current liabilities and $62 million was netted against noncurrent liabilities. 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.
Schedule Of Derivative Instruments Designated As Cash Flow Hedges	The following shows the effect on the Consolidated Statements of Operations and on Accumulated Other Comprehensive Loss (AOCL) of derivative instruments designated as cash flow hedges for the years ended December 31, 2018 , 2017 and 2016 . Amount of Pre-Tax Gain (Loss) Recognized in AOCL on Derivatives (Effective Portion) Location of Pre-Tax Gain (Loss) Reclassified from AOCL into Income Amount of Pre-Tax Gain (Loss) Reclassified from AOCL into Income (Effective Portion) Derivatives in Cash Flow Hedging Relationships Years Ended December 31, Years Ended December 31, 2018 2017 2016 2018 2017 2016 Millions Millions PSEG Interest Rate Swaps $ (2 ) $ — $ 3 Interest Expense $ — $ 3 $ — Total PSEG $ (2 ) $ — $ 3 $ — $ 3 $ — There were no pre-tax gains (losses) recognized in income on derivatives (ineffective portion) as of December 31, 2018 , 2017 and 2016 .
Schedule Of Reconciliation For Derivative Activity Included In Accumulated Other Comprehensive Loss	The following reconciles the Accumulated Other Comprehensive Income (Loss) for derivative activity included in the AOCL of PSEG on a pre-tax and after-tax basis. Accumulated Other Comprehensive Income (Loss) Pre-Tax After-Tax Millions Balance as of December 31, 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 December 31, 2018 $ (2 ) $ (1 )
Schedule Of Derivative Instruments Not Designated As Hedging Instruments And Impact On Results Of Operations	The following shows the effect on the Consolidated Statements of Operations of derivative instruments not designated as hedging instruments or as NPNS for the years ended December 31, 2018 , 2017 and 2016 . Power’s derivative contracts reflected in this table include contracts to hedge the purchase and sale of electricity and natural gas, and the purchase of fuel. The table does not include contracts which 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 Years Ended December 31, 2018 2017 2016 Millions PSEG and Power Energy-Related Contracts Operating Revenues $ (182 ) $ 66 $ 218 Energy-Related Contracts Energy Costs (9 ) (11 ) 4 Total PSEG and Power $ (191 ) $ 55 $ 222
Schedule Of Gross Volume, On Absolute Value Basis For Derivative Contracts	The following table summarizes the net notional volume purchases/(sales) of open derivative transactions by commodity as of December 31, 2018 and 2017 . Type Notional Total PSEG Power PSE&G Millions As of December 31, 2018 Natural Gas Dth 358 — 358 — Electricity MWh (74 ) — (74 ) — Financial Transmission Rights (FTRs) MWh 18 — 18 — As of December 31, 2017 Natural Gas Dth 154 — 154 — Electricity MWh (63 ) — (63 ) — FTRs MWh 6 — 6 —
Schedule Providing Credit Risk From Others, Net Of Collateral	. Rating Current Exposure Securities held as Collateral Net Exposure Number of Counterparties >10% Net Exposure of Counterparties >10% Millions Millions Investment Grade $ 264 $ 12 $ 252 1 $ 179 (A) Non-Investment Grade 1 — 1 — — Total $ 265 $ 12 $ 253 1 $ 179 (A) Represents net exposure with PSE&G.

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2018
Fair Value Disclosures [Abstract]
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis	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 December 31, 2018 and December 31, 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. Recurring Fair Value Measurements as of December 31, 2018 Description Total Netting (D) Quoted Market Prices for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Millions PSEG Assets: Cash Equivalents (A) $ 100 $ — $ 100 $ — $ — Derivative Contracts: Energy-Related Contracts (B) $ 12 $ (551 ) $ 29 $ 527 $ 7 NDT Fund (C) Equity Securities $ 900 $ — $ 898 $ 2 $ — Debt Securities—U.S. Treasury $ 171 $ — $ — $ 171 $ — Debt Securities—Govt Other $ 320 $ — $ — $ 320 $ — Debt Securities—Corporate $ 487 $ — $ — $ 487 $ — Rabbi Trust (C) Equity Securities $ 23 $ — $ 23 $ — $ — Debt Securities—U.S. Treasury $ 69 $ — $ — $ 69 $ — Debt Securities—Govt Other $ 40 $ — $ — $ 40 $ — Debt Securities—Corporate $ 92 $ — $ — $ 92 $ — Liabilities: Derivative Contracts: Energy-Related Contracts (B) $ (15 ) $ 704 $ (36 ) $ (677 ) $ (6 ) PSE&G Assets: Rabbi Trust (C) Equity Securities $ 5 $ — $ 5 $ — $ — Debt Securities—U.S. Treasury $ 14 $ — $ — $ 14 $ — Debt Securities—Govt Other $ 8 $ — $ — $ 8 $ — Debt Securities—Corporate $ 18 $ — $ — $ 18 $ — Power Assets: Derivative Contracts: Energy-Related Contracts (B) $ 12 $ (551 ) $ 29 $ 527 $ 7 NDT Fund (C) Equity Securities $ 900 $ — $ 898 $ 2 $ — Debt Securities—U.S. Treasury $ 171 $ — $ — $ 171 $ — Debt Securities—Govt Other $ 320 $ — $ — $ 320 $ — Debt Securities—Corporate $ 487 $ — $ — $ 487 $ — Rabbi Trust (C) Equity Securities $ 6 $ — $ 6 $ — $ — Debt Securities—U.S. Treasury $ 17 $ — $ — $ 17 $ — Debt Securities—Govt Other $ 10 $ — $ — $ 10 $ — Debt Securities—Corporate $ 23 $ — $ — $ 23 $ — Liabilities: Derivative Contracts: Energy-Related Contracts (B) $ (15 ) $ 704 $ (36 ) $ (677 ) $ (6 ) Recurring Fair Value Measurements as of December 31, 2017 Description Total Netting (D) Quoted Market Prices for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Millions PSEG Assets: Cash Equivalents (A) $ 223 $ — $ 223 $ — $ — Derivative Contracts: Energy-Related Contracts (B) $ 36 $ (433 ) $ 15 $ 442 $ 12 NDT Fund (C) 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 (C) 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 (B) $ (21 ) $ 477 $ (8 ) $ (485 ) $ (5 ) PSE&G Assets: Cash Equivalents (A) $ 223 $ — $ 223 $ — $ — Rabbi Trust (C) 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 (B) $ 36 $ (433 ) $ 15 $ 442 $ 12 NDT Fund (C) 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 (C) 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 (B) $ (21 ) $ 477 $ (8 ) $ (485 ) $ (5 ) (A) Represents money market mutual funds. (B) 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 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) The NDT Fund maintains investments in various equity and fixed income securities. The Rabbi Trust maintains investments in a Russell 3000 index fund and various fixed income securities. These securities are generally valued with prices that are either exchange provided (equity securities) or market transactions for comparable securities and/or broker quotes (fixed income securities). Level 1—Investments in marketable equity securities within the NDT Fund are primarily investments in common stocks across a broad range of industries and sectors. Most equity securities are priced utilizing the principal market close price or, in some cases, midpoint, bid or ask price. Certain other equity securities in the NDT and Rabbi Trust Funds consist primarily of investments in Dreyfus money market funds which seek a high level of current income as is consistent with the preservation of capital and the maintenance of liquidity. To pursue its goals, the funds normally invest in diversified portfolios of high quality, short-term, dollar-denominated debt securities and government securities. The funds’ NAV 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 investment grade corporate bonds, collateralized mortgage obligations, asset-backed securities and certain government and U.S. Treasury obligations or Federal Agency asset-backed securities and municipal bonds with a wide range of maturities. Since many fixed income securities do not trade on a daily basis, they are priced using an evaluated pricing methodology that varies by asset class and reflects observable market information such as the most recent exchange price or quoted bid for similar securities. Market-based standard inputs typically include benchmark yields, reported trades, broker/dealer quotes and issuer spreads. The preferred stocks are not actively traded on a daily basis and therefore, are also priced using an evaluated pricing methodology. Certain short-term investments are valued using observable market prices or market parameters such as time-to-maturity, coupon rate, quality rating and current yield. (D) Represents the netting of fair value balances with the same counterparty (where the right of offset exists) and the application of collateral. See Note 17. Financial Risk Management Activities for additional detail.
Schedule Of Quantitative Information About Level 3 Fair Value Measurements	d 2017 .
Changes In Level 3 Assets And (Liabilities) Measured At Fair Value On A Recurring Basis	ue. A reconciliation of the beginning and ending balances of Level 3 derivative contracts and securities for the years ended December 31, 2018 and 2017 , respectively, follows: Changes in Level 3 Assets and (Liabilities) Measured at Fair Value on a Recurring Basis for the Year Ended December 31, 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 Balance as of December 31, 2018 Millions PSEG Net Derivative Assets (Liabilities) $ 7 $ (6 ) $ — $ — $ — $ — $ 1 Power Net Derivative Assets (Liabilities) $ 7 $ (6 ) $ — $ — $ — $ — $ 1 Changes in Level 3 Assets and (Liabilities) Measured at Fair Value on a Recurring Basis for the Year Ended December 31, 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 December 31, 2017 Millions PSEG Net Derivative Assets (Liabilities) $ 1 $ 26 $ 5 $ — $ (24 ) $ (1 ) $ 7 PSE&G Net Derivative Assets (Liabilities) $ (5 ) $ — $ 5 $ — $ — $ — $ — Power Net Derivative Assets (Liabilities) $ 6 $ 26 $ — $ — $ (24 ) $ (1 ) $ 7 (A) Unrealized gains (losses) in the following table represent the change in derivative assets and liabilities still held as of December 31, 2018 and 2017. Years Ended December 31, 2018 2017 Total Gains (Losses) Unrealized Gains (Losses) Total Gains (Losses) Unrealized Gains (Losses) Millions PSEG and Power Operating Revenues $ (2 ) $ — $ 14 $ (9 ) Energy Costs (4 ) (6 ) 12 12 Total $ (6 ) $ (6 ) $ 26 $ 3 (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. (C) Represents $(24) million in settlements for derivative contracts in 2017 . (D) During the year ended December 31, 2017 , $(1) million of net derivatives assets/liabilities were transferred from Level 2 to Level 3. There were no transfers in 2018.
Schedule of Change in Derivative Assets and Liabilities still Held	Unrealized gains (losses) in the following table represent the change in derivative assets and liabilities still held as of December 31, 2018 and 2017. Years Ended December 31, 2018 2017 Total Gains (Losses) Unrealized Gains (Losses) Total Gains (Losses) Unrealized Gains (Losses) Millions PSEG and Power Operating Revenues $ (2 ) $ — $ 14 $ (9 ) Energy Costs (4 ) (6 ) 12 12 Total $ (6 ) $ (6 ) $ 26 $ 3

Stock Based Compensation (Table

Stock Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2018
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Accrual Adjustments	2018 2017 2016 Millions Compensation Cost included in Operation and Maintenance Expense $ 30 $ 31 $ 29 Income Tax Benefit Recognized in Consolidated Statement of Operations $ 9 $ 13 $ 12
Stock Options Activity	Changes in stock options for 2018 are summarized as follows: Options Weighted Average Exercise Price Weighted Average Remaining Years Contractual Term Aggregate Intrinsic Value Outstanding as of January 1, 2018 347,900 $ 33.49 Exercised 115,967 $ 33.49 Canceled/Forfeited — $ — Outstanding as of December 31, 2018 231,933 $ 33.49 1.0 $ 4,304,676 Exercisable at December 31, 2018 231,933 $ 33.49 1.0 $ 4,304,676
Activity For Options Exercised	Activity for options exercised for the years ended December 31, 2018 , 2017 and 2016 is shown below: 2018 2017 2016 Millions Total Intrinsic Value of Options Exercised $ 2 $ 5 $ 7 Cash Received from Options Exercised $ 4 $ 26 $ 22 Tax Benefit Realized from Options Exercised $ — $ — $ 1
Restricted Stock Units Activity	Changes in restricted stock units for the year ended December 31, 2018 are summarized as follows: Shares Weighted Average Grant Date Fair Value Weighted Average Remaining Years Contractual Term Aggregate Intrinsic Value Non-vested as of January 1, 2018 213,899 $ 42.32 Granted 277,261 $ 49.34 Vested 220,105 $ 46.02 Canceled/Forfeited 13,472 $ 44.94 Non-vested as of December 31, 2018 257,583 $ 46.58 1.2 $ 13,407,195
Performance Units Information	Changes in performance share units for the year ended December 31, 2018 are summarized as follows: Shares Weighted Average Grant Date Fair Value Weighted Average Remaining Years Contractual Term Aggregate Intrinsic Value Non-vested as of January 1, 2018 332,461 $ 45.29 Granted 378,800 $ 54.95 Vested 310,425 $ 49.63 Canceled/Forfeited 23,295 $ 48.57 Non-vested as of December 31, 2018 377,541 $ 51.94 1.7 $ 19,651,009

Other Income and Deductions (Ta

Other Income and Deductions (Tables)	12 Months Ended
	Dec. 31, 2018
Other Income and Deductions Disclosure [Abstract]
Schedule Of Other Income	PSE&G Power Other (A) Consolidated Total Millions Year Ended December 31, 2018 NDT Fund Interest and Dividends $ — $ 52 $ — $ 52 Allowance for Funds Used During Construction 54 — — 54 Solar Loan Interest 18 — — 18 Donations — — (17 ) (17 ) Other 8 (31 ) 1 (22 ) Total Other Income (Deductions) $ 80 $ 21 $ (16 ) $ 85 Year Ended December 31, 2017 NDT Fund Interest and Dividends $ — $ 45 $ — $ 45 Allowance for Funds Used During Construction 56 — — 56 Solar Loan Interest 21 — — 21 Donations (1 ) (2 ) (25 ) (28 ) Other 9 (23 ) 2 (12 ) Total Other Income (Deductions) $ 85 $ 20 $ (23 ) $ 82 Year Ended December 31, 2016 NDT Fund Interest and Dividends $ — $ 43 $ — $ 43 Allowance for Funds Used During Construction 49 — — 49 Solar Loan Interest 22 — — 22 Donations (1 ) (1 ) — (2 ) Other 9 (19 ) — (10 ) Total Other Income (Deductions) $ 79 $ 23 $ — $ 102
Schedule Of Other Deductions	(A) Other consists of activity at PSEG (as parent company), Energy Holdings, Services, PSEG LI and intercompany eliminations.

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2018
Income Taxes [Line Items]
Unrecognized Tax Benefits	2018 PSEG PSE&G Power Energy Holdings Millions Total Amount of Unrecognized Tax Benefits as of January 1, 2018 $ 334 $ 135 $ 142 $ 53 Increases as a Result of Positions Taken in a Prior Period 11 4 4 3 Decreases as a Result of Positions Taken in a Prior Period (70 ) (31 ) (37 ) (2 ) Increases as a Result of Positions Taken during the Current Period 52 3 48 — Decreases as a Result of Positions Taken during the Current Period (3 ) (3 ) — — Decreases as a Result of Settlements with Taxing Authorities (6 ) — (6 ) — Decreases due to Lapses of Applicable Statute of Limitations — — — — Total Amount of Unrecognized Tax Benefits as of December 31, 2018 $ 318 $ 108 $ 151 $ 54 Accumulated Deferred Income Taxes Associated with Unrecognized Tax Benefits (173 ) (57 ) (104 ) (12 ) Regulatory Asset—Unrecognized Tax Benefits (46 ) (46 ) — — Total Amount of Unrecognized Tax Benefits that if Recognized, would Impact the Effective Tax Rate (including Interest and Penalties) $ 99 $ 5 $ 47 $ 42 2017 PSEG PSE&G Power Energy Holdings Millions Total Amount of Unrecognized Tax Benefits as of January 1, 2017 $ 328 $ 140 $ 128 $ 57 Increases as a Result of Positions Taken in a Prior Period 40 15 18 8 Decreases as a Result of Positions Taken in a Prior Period (32 ) (11 ) (10 ) (13 ) Increases as a Result of Positions Taken during the Current Period 12 5 6 1 Decreases as a Result of Positions Taken during the Current Period (1 ) (1 ) — — Decreases as a Result of Settlements with Taxing Authorities — — — — Decreases due to Lapses of Applicable Statute of Limitations (13 ) (13 ) — — Total Amount of Unrecognized Tax Benefits as of December 31, 2017 $ 334 $ 135 $ 142 $ 53 Accumulated Deferred Income Taxes Associated with Unrecognized Tax Benefits (157 ) (73 ) (72 ) (12 ) Regulatory Asset—Unrecognized Tax Benefits (56 ) (56 ) — — Total Amount of Unrecognized Tax Benefits that if Recognized, would Impact the Effective Tax Rate (including Interest and Penalties) $ 121 $ 6 $ 70 $ 41 2016 PSEG PSE&G Power Energy Holdings Millions Total Amount of Unrecognized Tax Benefits as of January 1, 2016 $ 386 $ 181 $ 111 $ 93 Increases as a Result of Positions Taken in a Prior Period 12 3 6 2 Decreases as a Result of Positions Taken in a Prior Period (62 ) (23 ) (1 ) (38 ) Increases as a Result of Positions Taken during the Current Period 19 6 12 — Decreases as a Result of Positions Taken during the Current Period — — — — Decreases as a Result of Settlements with Taxing Authorities — — — — Decreases due to Lapses of Applicable Statute of Limitations (27 ) (27 ) — — Total Amount of Unrecognized Tax Benefits as of December 31, 2016 $ 328 $ 140 $ 128 $ 57 Accumulated Deferred Income Taxes Associated with Unrecognized Tax Benefits (200 ) (106 ) (74 ) (20 ) Regulatory Asset—Unrecognized Tax Benefits (31 ) (31 ) — — Total Amount of Unrecognized Tax Benefits that if Recognized, would Impact the Effective Tax Rate (including Interest and Penalties) $ 97 $ 3 $ 54 $ 37
Interest And Penalties Related To Uncertain Tax Positions	PSEG and its subsidiaries include accrued interest and penalties related to uncertain tax positions required to be recorded, as Income Tax Expense in the Consolidated Statements of Operations. Accumulated interest and penalties that are recorded on the Consolidated Balance Sheets on uncertain tax positions were as follows: Accumulated Interest and Penalties on Uncertain Tax Positions as of December 31, 2018 2017 2016 Millions PSE&G $ 12 $ 25 $ 22 Power 9 24 17 Energy Holdings 22 21 20 Total $ 43 $ 70 $ 59
Possible Decrease In Total Unrecognized Tax Benefits Including Interest	t is reasonably possible that total unrecognized tax benefits will significantly increase or decrease within the next twelve months due to either agreements with various taxing authorities upon audit, the expiration of the Statute of Limitations, or other pending tax matters. These potential increases or decreases are as follows: Possible (Increase)/Decrease in Total Unrecognized Tax Benefits Over the next 12 Months Millions PSEG $ 112 PSE&G $ 62 Power $ 34
Description Of Income Tax Years By Material Jurisdictions	A description of income tax years that remain subject to examination by material jurisdictions, where an examination has not already concluded are: PSEG PSE&G Power United States Federal 2011-2017 N/A N/A New Jersey 2006-2017 2011-2017 N/A Pennsylvania 2015-2017 2015-2017 N/A Connecticut 2016-2017 N/A N/A California 2006-2017 N/A N/A New York 2017 N/A 2017
PSEG [Member]
Income Taxes [Line Items]
Schedule of Effective Income Tax Rate Reconciliation	A reconciliation of reported income tax expense for PSEG with the amount computed by multiplying pre-tax income by the statutory federal income tax rate of 21% in 2018 and 35% in 2017 and 2016 is as follows: Years Ended December 31, PSEG 2018 2017 2016 Millions Net Income $ 1,438 $ 1,574 $ 887 Income Taxes: Operating Income: Current (Benefit) Expense: Federal $ (97 ) $ 86 $ (74 ) State 83 (31 ) 61 Total Current (14 ) 55 (13 ) Deferred Expense (Benefit): Federal 373 (482 ) 311 State 71 92 28 Total Deferred 444 (390 ) 339 Investment Tax Credit (ITC) (13 ) 29 85 Total Income Tax Expense (Benefit) $ 417 $ (306 ) $ 411 Pre-Tax Income $ 1,855 $ 1,268 $ 1,298 Tax Computed at Statutory Rate 21% in 2018 and 35% in 2017 and 2016 $ 390 $ 444 $ 454 Increase (Decrease) Attributable to Flow-Through of Certain Tax Adjustments: State Income Taxes (net of federal income tax) 123 36 56 Uncertain Tax Positions (24 ) (3 ) (31 ) Manufacturing Deduction — (13 ) (17 ) NDT Fund (13 ) 19 3 Plant-Related Items (10 ) (23 ) (20 ) Tax Credits (16 ) (22 ) (25 ) Audit Settlement — 6 — Tax Adjustment Credit (30 ) — — Deferred Tax Expense (Benefit) - Tax Act 3 (755 ) — Other (6 ) 5 (9 ) Sub-Total 27 (750 ) (43 ) Total Income Tax Expense (Benefit) $ 417 $ (306 ) $ 411 Effective Income Tax Rate 22.5 % (24.1 )% 31.7 %
Deferred Income Taxes	The following is an analysis of deferred income taxes for PSEG: As of December 31, PSEG 2018 2017 Millions Deferred Income Taxes Assets: Noncurrent Regulatory Liability Excess Deferred Tax $ 606 $ 602 OPEB 163 217 Related to Uncertain Tax Position 71 142 Total Noncurrent Assets $ 840 $ 961 Liabilities: Noncurrent: Plant-Related Items $ 4,817 $ 4,257 New Jersey Corporate Business Tax 756 674 Leasing Activities 307 384 AROs and NDT Fund 196 233 Pension Costs 111 123 Taxes Recoverable Through Future Rates (net) 89 80 Other 12 171 Total Noncurrent Liabilities $ 6,288 $ 5,922 Summary of Accumulated Deferred Income Taxes: Net Noncurrent Deferred Income Tax Liabilities $ 5,448 $ 4,961 ITC 265 279 Net Total Noncurrent Deferred Income Taxes and ITC $ 5,713 $ 5,240 The deferred tax effect of certain assets and liabilities is presented in the table above net of the deferred tax effect associated with the respective regulatory deferrals. In December 2017, new tax legislation was enacted, reducing the statutory U.S. corporate income tax rate from a maximum of 35% to 21%, effective January 1, 2018. PSEG is subject to ASC 740, which requires that the effect on deferred tax assets and liabilities of a change in tax rates be recognized in the period the tax rate was enacted.
PSE&G [Member]
Income Taxes [Line Items]
Schedule of Effective Income Tax Rate Reconciliation	A reconciliation of reported income tax expense for PSE&G with the amount computed by multiplying pre-tax income by the statutory federal income tax rate of 21% in 2018 and 35% in 2017 and 2016 is as follows: Years Ended December 31, PSE&G 2018 2017 2016 Millions Net Income $ 1,067 $ 973 $ 889 Income Taxes: Operating Income: Current (Benefit) Expense: Federal $ (62 ) $ (52 ) $ (153 ) State 1 (1 ) 10 Total Current (61 ) (53 ) (143 ) Deferred Expense: Federal 287 492 551 State 122 129 102 Total Deferred 409 621 653 ITC (4 ) (5 ) 5 Total Income Tax Expense $ 344 $ 563 $ 515 Pre-Tax Income $ 1,411 $ 1,536 $ 1,404 Tax Computed at Statutory Rate 21% in 2018 and 35% in 2017 and 2016 $ 296 $ 538 $ 491 Increase (Decrease) Attributable to Flow-Through of Certain Tax Adjustments: State Income Taxes (net of federal income tax) 98 83 72 Uncertain Tax Positions (1 ) (9 ) (18 ) Plant-Related Items (10 ) (23 ) (20 ) Tax Credits (8 ) (9 ) (7 ) Tax Adjustment Credit (30 ) — — Deferred Tax Benefit - Tax Act — (10 ) — Other (1 ) (7 ) (3 ) Sub-Total 48 25 24 Total Income Tax Expense $ 344 $ 563 $ 515 Effective Income Tax Rate 24.4 % 36.7 % 36.7 %
Deferred Income Taxes	The following is an analysis of deferred income taxes for PSE&G: As of December 31, PSE&G 2018 2017 Millions Deferred Income Taxes Assets: Noncurrent: Regulatory Liability Excess Deferred Tax $ 606 $ 602 OPEB 114 116 Total Noncurrent Assets $ 720 $ 718 Liabilities: Noncurrent: Plant-Related Items $ 3,622 $ 3,311 New Jersey Corporate Business Tax 486 378 Pension Costs 159 152 Conservation Costs 36 24 Taxes Recoverable Through Future Rates (net) 89 80 Other 84 86 Total Noncurrent Liabilities $ 4,476 $ 4,031 Summary of Accumulated Deferred Income Taxes: Net Noncurrent Deferred Income Tax Liabilities $ 3,756 $ 3,313 ITC 74 78 Net Total Noncurrent Deferred Income Taxes and ITC $ 3,830 $ 3,391 The deferred tax effect of certain assets and liabilities is presented in the table above net of the deferred tax effect associated with the respective regulatory deferrals. In December 2017, new tax legislation was enacted, reducing the statutory U.S. corporate income tax rate from a maximum of 35% to 21%, effective January 1, 2018. PSE&G is subject to ASC 740, which requires that the effect on deferred tax assets and liabilities of a change in tax rates be recognized in the period the tax rate was enacted.
Power [Member]
Income Taxes [Line Items]
Schedule of Effective Income Tax Rate Reconciliation	A reconciliation of reported income tax expense for Power with the amount computed by multiplying pre-tax income by the statutory federal income tax rate of 21% in 2018 and 35% in 2017 and 2016 is as follows: Years Ended December 31, Power 2018 2017 2016 Millions Net Income $ 365 $ 479 $ 18 Income Taxes: Operating Income: Current (Benefit) Expense: Federal $ (164 ) $ 95 $ 107 State 24 (17 ) 40 Total Current (140 ) 78 147 Deferred Expense (Benefit): Federal 214 (804 ) (222 ) State 1 (37 ) (68 ) Total Deferred 215 (841 ) (290 ) ITC (9 ) 34 82 Total Income Tax Expense (Benefit) $ 66 $ (729 ) $ (61 ) Pre-Tax Income (Loss) $ 431 $ (250 ) $ (43 ) Tax Computed at Statutory Rate 21% in 2018 and 35% in 2017 and 2016 $ 91 $ (88 ) $ (15 ) Increase (Decrease) Attributable to Flow-Through of Certain Tax Adjustments: State Income Taxes (net of federal income tax) 21 (36 ) (18 ) Manufacturing Deduction — (13 ) (17 ) NDT Fund (13 ) 19 3 Tax Credits (7 ) (12 ) (18 ) Uncertain Tax Positions (24 ) 7 9 Audit Settlement — 1 — Deferred Tax Benefit - Tax Act (1 ) (610 ) — Other (1 ) 3 (5 ) Sub-Total (25 ) (641 ) (46 ) Total Income Tax Expense (Benefit) $ 66 $ (729 ) $ (61 ) Effective Income Tax Rate 15.3 % 291.6 % 141.9 %
Deferred Income Taxes	The following is an analysis of deferred income taxes for Power: As of December 31, Power 2018 2017 Millions Deferred Income Taxes Assets: Noncurrent: Related to Uncertain Tax Positions $ 60 $ 45 Pension Costs 52 40 Contractual Liabilities & Environmental Costs 9 12 Other 98 93 Total Noncurrent Assets $ 219 $ 190 Liabilities: Noncurrent: Plant-Related Items $ 1,189 $ 935 AROs and NDT Fund 197 235 New Jersey Corporate Business Tax 260 225 Total Noncurrent Liabilities $ 1,646 $ 1,395 Summary of Accumulated Deferred Income Taxes: Net Noncurrent Deferred Income Tax Liabilities $ 1,427 $ 1,205 ITC 192 201 Net Total Noncurrent Deferred Income Taxes and ITC $ 1,619 $ 1,406

Accumulated Other Comprehensi_2

Accumulated Other Comprehensive Income (Loss), Net of Tax Accumulated Other Comprehensive Income (Loss), Net of Tax (Tables)	12 Months Ended
	Dec. 31, 2018
Equity [Abstract]
Schedule of Accumulated Other Comprehensive Income (Loss) [Table Text Block]	PSEG Other Comprehensive Income (Loss) Accumulated Other Comprehensive Income (Loss) Cash Flow Hedges Pension and OPEB Plans Available-for -Sale Securities Total Millions Balance as of December 31, 2015 $ — $ (386 ) $ 91 $ (295 ) Other Comprehensive Income before Reclassifications 2 (45 ) 40 (3 ) Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) — 33 2 35 Net Current Period Other Comprehensive Income (Loss) 2 (12 ) 42 32 Balance as of December 31, 2016 $ 2 $ (398 ) $ 133 $ (263 ) Other Comprehensive Income before Reclassifications — (32 ) 109 77 Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) (2 ) 24 (65 ) (43 ) Net Current Period Other Comprehensive Income (Loss) (2 ) (8 ) 44 34 Balance as of December 31, 2017 $ — $ (406 ) $ 177 $ (229 ) Cumulative Effect Adjustment to Reclassify Unrealized Net Gains on Equity Investments to Retained Earnings — — (176 ) (176 ) Current Period Other Comprehensive Income (Loss) Other Comprehensive Income before Reclassifications (1 ) 17 (25 ) (9 ) Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) — 29 8 37 Net Current Period Other Comprehensive Income (Loss) (1 ) 46 (17 ) 28 Net Change in Accumulated Other Comprehensive Income (Loss) (1 ) 46 (193 ) (148 ) Balance as of December 31, 2018 $ (1 ) $ (360 ) $ (16 ) $ (377 ) Power Other Comprehensive Income (Loss) Accumulated Other Comprehensive Income (Loss) Cash Flow Hedges Pension and OPEB Plans Available-for -Sale Securities Total Millions Balance as of December 31, 2015 $ — $ (327 ) $ 87 $ (240 ) Other Comprehensive Income before Reclassifications — (42 ) 39 (3 ) Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) — 29 3 32 Net Current Period Other Comprehensive Income (Loss) — (13 ) 42 29 Balance as of December 31, 2016 $ — $ (340 ) $ 129 $ (211 ) Other Comprehensive Income before Reclassifications — (28 ) 106 78 Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) — 21 (60 ) (39 ) Net Current Period Other Comprehensive Income (Loss) — (7 ) 46 39 Balance as of December 31, 2017 $ — $ (347 ) $ 175 $ (172 ) Cumulative Effect Adjustment to Reclassify Unrealized Net Gains on Equity Investments to Retained Earnings — — (175 ) (175 ) Current Period Other Comprehensive Income (Loss) Other Comprehensive Income before Reclassifications — 16 (19 ) (3 ) Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) — 25 6 31 Net Current Period Other Comprehensive Income (Loss) — 41 (13 ) 28 Net Change in Accumulated Other Comprehensive Income (Loss) — 41 (188 ) (147 ) Balance as of December 31, 2018 $ — $ (306 ) $ (13 ) $ (319 )
Reclassification out of Accumulated Other Comprehensive Income [Table Text Block]	PSEG Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement Year Ended December 31, 2016 Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) Location of Pre-Tax Amount In Statement of Operations Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount Millions Pension and OPEB Plans Amortization of Prior Service (Cost) Credit Non-Operating Pension and OPEB Credits (Costs) $ 12 $ (5 ) $ 7 Amortization of Actuarial Loss Non-Operating Pension and OPEB Credits (Costs) (68 ) 28 (40 ) Total Pension and OPEB Plans (56 ) 23 (33 ) Available-for-Sale Securities Realized Gains (Losses) and Other-Than-Temporary Impairments (OTTI) Net Gains (Losses) on Trust Investments (6 ) 4 (2 ) Total Available-for-Sale Securities (6 ) 4 (2 ) Total $ (62 ) $ 27 $ (35 ) Power Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement Year Ended December 31, 2016 Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) Location of Pre-Tax Amount In Statement of Operations Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount Millions Pension and OPEB Plans Amortization of Prior Service (Cost) Credit Non-Operating Pension and OPEB Credits (Costs) $ 11 $ (5 ) $ 6 Amortization of Actuarial Loss Non-Operating Pension and OPEB Credits (Costs) (59 ) 24 (35 ) Total Pension and OPEB Plans (48 ) 19 (29 ) Available-for-Sale Securities Realized Gains (Losses) and OTTI Net Gains (Losses) on Trust Investments (6 ) 3 (3 ) Total Available-for-Sale Securities (6 ) 3 (3 ) Total $ (54 ) $ 22 $ (32 ) PSEG Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement Year Ended December 31, 2017 Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) Location of Pre-Tax Amount In Statement of Operations Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount Millions Cash Flow Hedges Interest Rate Swaps Interest Expense $ 3 $ (1 ) $ 2 Total Cash Flow Hedges 3 (1 ) 2 Pension and OPEB Plans Amortization of Prior Service (Cost) Credit Non-Operating Pension and OPEB Credits (Costs) 10 (4 ) 6 Amortization of Actuarial Loss Non-Operating Pension and OPEB Credits (Costs) (51 ) 21 (30 ) Total Pension and OPEB Plans (41 ) 17 (24 ) Available-for-Sale Securities Realized Gains (Losses) and OTTI Net Gains (Losses) on Trust Investments 134 (69 ) 65 Total Available-for-Sale Securities 134 (69 ) 65 Total $ 96 $ (53 ) $ 43 Power Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement Year Ended December 31, 2017 Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) Location of Pre-Tax Amount In Statement of Operations Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount Millions Pension and OPEB Plans Amortization of Prior Service (Cost) Credit Non-Operating Pension and OPEB Credits (Costs) $ 9 $ (4 ) $ 5 Amortization of Actuarial Loss Non-Operating Pension and OPEB Credits (Costs) (44 ) 18 (26 ) Total Pension and OPEB Plans (35 ) 14 (21 ) Available-for-Sale Securities Realized Gains (Losses) and OTTI Net Gains (Losses) on Trust Investments 125 (65 ) 60 Total Available-for-Sale Securities 125 (65 ) 60 Total $ 90 $ (51 ) $ 39 PSEG Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement Year Ended December 31, 2018 Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) Location of Pre-Tax Amount In Statement of Operations Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount Millions Pension and OPEB Plans Amortization of Prior Service (Cost) Credit Non-Operating Pension and OPEB Credits (Costs) $ 6 $ (2 ) $ 4 Amortization of Actuarial Loss Non-Operating Pension and OPEB Credits (Costs) (47 ) 14 (33 ) Total Pension and OPEB Plans (41 ) 12 (29 ) Available-for-Sale Securities Realized Gains (Losses) and OTTI Net Gains (Losses) on Trust Investments (13 ) 5 (8 ) Total Available-for-Sale Securities (13 ) 5 (8 ) Total $ (54 ) $ 17 $ (37 ) Power Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement Year Ended December 31, 2018 Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) Location of Pre-Tax Amount In Statement of Operations Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount Millions Pension and OPEB Plans Amortization of Prior Service (Cost) Credit Non-Operating Pension and OPEB Credits (Costs) $ 5 $ (1 ) $ 4 Amortization of Actuarial Loss Non-Operating Pension and OPEB Credits (Costs) (40 ) 11 (29 ) Total Pension and OPEB Plans (35 ) 10 (25 ) Available-for-Sale Securities Realized Gains (Losses) and OTTI Net Gains (Losses) on Trust Investments (11 ) 5 (6 ) Total Available-for-Sale Securities (11 ) 5 (6 ) Total $ (46 ) $ 15 $ (31 )

Earnings Per Share (EPS) and _2

Earnings Per Share (EPS) and Dividends (Tables)	12 Months Ended
	Dec. 31, 2018
Earnings Per Share [Abstract]
Basic And Diluted Earnings Per Share Computation	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: Years Ended December 31, 2018 2017 2016 Basic Diluted Basic Diluted Basic Diluted EPS Numerator: (Millions) Net Income $ 1,438 $ 1,438 $ 1,574 $ 1,574 $ 887 $ 887 EPS Denominator: (Millions) Weighted Average Common Shares Outstanding 504 504 505 505 505 505 Effect of Stock Based Compensation Awards — 3 — 2 — 3 Total Shares 504 507 505 507 505 508 EPS: Net Income $ 2.85 $ 2.83 $ 3.12 $ 3.10 $ 1.76 $ 1.75
Dividend Payments On Common Stock	Years Ended December 31, Dividend Payments on Common Stock 2018 2017 2016 Per Share $ 1.80 $ 1.72 $ 1.64 in Millions $ 910 $ 870 $ 830

Financial Information By Busi_2

Financial Information By Business Segments (Tables)	12 Months Ended
	Dec. 31, 2018
Segment Reporting [Abstract]
Financial Information By Business Segments	PSE&G Power Other (A) Eliminations (B) Consolidated Total Millions Year Ended December 31, 2018 Operating Revenues $ 6,471 $ 4,146 $ 571 $ (1,492 ) $ 9,696 Depreciation and Amortization 770 354 34 — 1,158 Operating Income (Loss) 1,606 596 96 — 2,298 Income from Equity Method Investments — 15 — — 15 Interest Income 21 5 9 (6 ) 29 Interest Expense 333 76 73 (6 ) 476 Income (Loss) before Income Taxes 1,411 431 13 — 1,855 Income Tax Expense (Benefit) 344 66 7 — 417 Net Income (Loss) $ 1,067 $ 365 $ 6 $ — $ 1,438 Gross Additions to Long-Lived Assets $ 2,896 $ 996 $ 20 $ — $ 3,912 As of December 31, 2018 Total Assets $ 31,109 $ 12,594 $ 2,604 $ (981 ) $ 45,326 Investments in Equity Method Subsidiaries $ — $ 86 $ — $ — $ 86 PSE&G Power Other (A) Eliminations (B) Consolidated Total Millions Year Ended December 31, 2017 Operating Revenues $ 6,324 $ 3,860 $ 466 $ (1,556 ) $ 9,094 Depreciation and Amortization 685 1,268 33 — 1,986 Operating Income (Loss) 1,760 (367 ) 36 — 1,429 Income from Equity Method Investments — 14 — — 14 Interest Income 24 3 5 (2 ) 30 Interest Expense 303 50 40 (2 ) 391 Income (Loss) before Income Taxes 1,536 (250 ) (18 ) — 1,268 Income Tax Expense (Benefit) 563 (729 ) (140 ) — (306 ) Net Income (Loss) $ 973 $ 479 $ 122 $ — $ 1,574 Gross Additions to Long-Lived Assets $ 2,919 $ 1,231 $ 40 $ — $ 4,190 As of December 31, 2017 Total Assets $ 28,554 $ 12,418 $ 2,666 $ (922 ) $ 42,716 Investments in Equity Method Subsidiaries $ — $ 87 $ — $ — $ 87 PSE&G Power Other (A) Eliminations (B) Consolidated Total Millions Year Ended December 31, 2016 Operating Revenues $ 6,303 $ 3,861 $ 370 $ (1,568 ) $ 8,966 Depreciation and Amortization 565 881 30 — 1,476 Operating Income (Loss) 1,629 17 (48 ) — 1,598 Income from Equity Method Investments — 11 — — 11 Interest Income 24 4 4 (2 ) 30 Interest Expense 289 84 14 (2 ) 385 Income (Loss) before Income Taxes 1,404 (43 ) (63 ) — 1,298 Income Tax Expense (Benefit) 515 (61 ) (43 ) — 411 Net Income (Loss) $ 889 $ 18 $ (20 ) $ — $ 887 Gross Additions to Long-Lived Assets $ 2,816 $ 1,343 $ 40 $ — $ 4,199 As of December 31, 2016 Total Assets $ 26,288 $ 12,193 $ 2,373 $ (784 ) $ 40,070 Investments in Equity Method Subsidiaries $ — $ 102 $ — $ — $ 102 (A) Includes amounts applicable to Energy Holdings and PSEG LI, which are below the quantitative threshold for separate disclosure as reportable segments. Other also includes amounts applicable to PSEG (parent corporation) and Services. (B) Intercompany eliminations primarily relate to intercompany transactions between PSE&G and Power. For a further discussion of the intercompany transactions between PSE&G and Power, see Note 25. Related-Party Transactions .

Related-Party Transactions (Tab

Related-Party Transactions (Tables)	12 Months Ended
	Dec. 31, 2018
PSE&G [Member]
Related Party Transaction [Line Items]
Schedule Of Related Party Transactions, Revenue	The financial statements for PSE&G include transactions with related parties presented as follows: Years Ended December 31, Related Party Transactions 2018 2017 2016 Millions Billings from Affiliates: Net Billings from Power primarily through BGS and BGSS (A) $ 1,514 $ 1,580 $ 1,587 Administrative Billings from Services (B) 333 331 312 Total Billings from Affiliates $ 1,847 $ 1,911 $ 1,899
Schedule Of Related Party Transactions, Payables	Years Ended December 31, Related Party Transactions 2018 2017 Millions Receivables from PSEG (C) $ 123 $ — Payable to Power (A) $ 245 $ 221 Payable to Services (B) 76 78 Payable to PSEG (C) — 41 Accounts Payable—Affiliated Companies $ 321 $ 340 Working Capital Advances to Services (D) $ 33 $ 33 Long-Term Accrued Taxes Payable $ 69 $ 91
Power [Member]
Related Party Transaction [Line Items]
Schedule Of Related Party Transactions, Revenue	The financial statements for Power include transactions with related parties presented as follows: Years Ended December 31, Related Party Transactions 2018 2017 2016 Millions Billings to Affiliates: Net Billings to PSE&G primarily through BGS and BGSS (A) $ 1,514 $ 1,580 1,587 Billings from Affiliates: Administrative Billings from Services (B) $ 145 $ 168 $ 179
Schedule Of Related Party Transactions, Receivables	Years Ended December 31, Related Party Transactions 2018 2017 Millions Receivable from PSE&G (A) $ 245 $ 221 Receivables from PSEG (C) 29 — Accounts Receivable—Affiliated Companies $ 274 $ 221 Payable to Services (B) $ 16 $ 28 Payable to PSEG (C) — 29 Accounts Payable—Affiliated Companies $ 16 $ 57 Short-Term Loan due to Affiliate (E) $ 193 $ 281 Working Capital Advances to Services (D) $ 17 $ 17 Long-Term Accrued Taxes Payable $ 76 $ 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 Consolidated Balance Sheets. (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.

Selected Quarterly Data (Tables

Selected Quarterly Data (Tables)	12 Months Ended
	Dec. 31, 2018
Schedule of Quarterly Data [Line Items]
Schedule Of Selected Quarterly Data	The information shown in the following tables, in the opinion of PSEG, PSE&G and Power includes all adjustments, consisting only of normal recurring accruals, necessary to fairly present such amounts. Quarter Ended March 31, (A) June 30, (A) September 30, December 31, (A) 2018 2017 2018 2017 2018 2017 2018 2017 PSEG Consolidated: Millions, except per share data Operating Revenues $ 2,818 $ 2,591 $ 2,016 $ 2,142 $ 2,394 $ 2,254 $ 2,468 $ 2,107 Operating Income $ 832 $ 178 $ 411 $ 195 $ 554 $ 693 $ 501 $ 363 Net Income $ 558 $ 114 $ 269 $ 109 $ 412 $ 395 $ 199 $ 956 Earnings Per Share: Basic: Net Income $ 1.11 $ 0.23 $ 0.53 $ 0.22 $ 0.82 $ 0.78 $ 0.39 $ 1.89 Diluted: Net Income $ 1.10 $ 0.22 $ 0.53 $ 0.22 $ 0.81 $ 0.78 $ 0.39 $ 1.88 Weighted Average Common Shares Outstanding: Basic 504 505 504 505 504 505 504 505 Diluted 507 508 507 507 507 507 508 508
PSE&G [Member]
Schedule of Quarterly Data [Line Items]
Schedule Of Selected Quarterly Data	Quarter Ended March 31, June 30, September 30, December 31, 2018 2017 2018 2017 2018 2017 2018 2017 PSE&G: Millions Operating Revenues $ 1,845 $ 1,826 $ 1,386 $ 1,393 $ 1,595 $ 1,530 $ 1,645 $ 1,575 Operating Income $ 482 $ 523 $ 358 $ 380 $ 421 $ 461 $ 345 $ 396 Net Income $ 319 $ 299 $ 231 $ 208 $ 278 $ 246 $ 239 $ 220
Power [Member]
Schedule of Quarterly Data [Line Items]
Schedule Of Selected Quarterly Data	Quarter Ended March 31, (A) June 30, (A) September 30, December 31, (A) 2018 2017 2018 2017 2018 2017 2018 2017 Power: Millions Operating Revenues $ 1,403 $ 1,269 $ 767 $ 918 $ 868 $ 846 $ 1,108 $ 827 Operating Income (Loss) $ 329 $ (305 ) $ 42 $ (189 ) $ 112 $ 211 $ 113 $ (84 ) Net Income (Loss) $ 234 $ (170 ) $ 41 $ (97 ) $ 125 $ 136 $ (35 ) $ 610 (A) The increases in Operating Income at PSEG consolidated and Power in the first and second quarters of 2018 as compared to the same quarters in 2017 were primarily due to higher costs in 2017 related to closing the coal/gas Hudson and Mercer units, which were fully depreciated as of June 1, 2017. The increases in Operating Income at PSEG consolidated and Power in the fourth quarter 2018 as compared to the same quarter in 2017 were primarily due to lower MTM losses and a gain on the sale of the Hudson and Mercer units. The decreases in Net Income at PSEG consolidated and Power in the fourth quarter 2018 as compared to the same quarter in 2017 also reflected the impact of the one-time benefit recorded in December 2017 as a result of the remeasurement of deferred tax balances and the inclusion in 2018 of net unrealized losses on equity investments in the NDT Fund in accordance with new accounting guidance.

Guarantees of Debt (Tables)

Guarantees of Debt (Tables)	12 Months Ended
	Dec. 31, 2018
Guarantees of Debt [Line Items]
Schedule Of Financial Statements Of Guarantors	The following tables present condensed financial information for the guarantor subsidiaries, as well as Power’s non-guarantor subsidiaries, as of December 31, 2018 and 2017 and for the years ended December 31, 2018 , 2017 and 2016 . Power Guarantor Subsidiaries Other Subsidiaries Consolidating Adjustments Total Millions Year Ended December 31, 2018 Operating Revenues $ — $ 4,078 $ 224 $ (156 ) $ 4,146 Operating Expenses 14 3,460 232 (156 ) 3,550 Operating Income (Loss) (14 ) 618 (8 ) — 596 Equity Earnings (Losses) of Subsidiaries 406 (28 ) 15 (378 ) 15 Net Gains (Losses) on Trust Investments (1 ) (139 ) — — (140 ) Other Income (Deductions) 135 166 — (280 ) 21 Non-Operating Pension and OPEB Credits (Costs) — 13 2 — 15 Interest Expense (230 ) (96 ) (30 ) 280 (76 ) Income Tax Benefit (Expense) 69 (143 ) 8 — (66 ) Net Income (Loss) $ 365 $ 391 $ (13 ) $ (378 ) $ 365 Comprehensive Income (Loss) $ 393 $ 379 $ (13 ) $ (366 ) $ 393 As of December 31, 2018 Current Assets $ 4,317 $ 1,479 $ 304 $ (4,593 ) $ 1,507 Property, Plant and Equipment, net 49 4,971 3,822 — 8,842 Investment in Subsidiaries 5,062 1,107 — (6,169 ) — Noncurrent Assets 273 2,109 101 (238 ) 2,245 Total Assets $ 9,701 $ 9,666 $ 4,227 $ (11,000 ) $ 12,594 Current Liabilities $ 437 $ 2,971 $ 2,027 $ (4,593 ) $ 842 Noncurrent Liabilities 513 1,996 730 (238 ) 3,001 Long-Term Debt 2,791 — — — 2,791 Member’s Equity 5,960 4,699 1,470 (6,169 ) 5,960 Total Liabilities and Member’s Equity $ 9,701 $ 9,666 $ 4,227 $ (11,000 ) $ 12,594 Year Ended December 31, 2018 Net Cash Provided By (Used In) Operating Activities $ (74 ) $ 1,007 $ 42 $ 109 $ 1,084 Net Cash Provided By (Used In) Investing Activities $ (402 ) $ (1,034 ) $ (406 ) $ 791 $ (1,051 ) Net Cash Provided By (Used In) Financing Activities $ 476 $ 27 $ 354 $ (900 ) $ (43 ) Power Guarantor Subsidiaries Other Subsidiaries Consolidating Adjustments Total Millions Year Ended December 31, 2017 Operating Revenues $ — $ 3,821 $ 174 $ (135 ) $ 3,860 Operating Expenses 8 4,159 195 (135 ) 4,227 Operating Income (Loss) (8 ) (338 ) (21 ) — (367 ) Equity Earnings (Losses) of Subsidiaries 567 60 14 (627 ) 14 Net Gains (Losses) on Trust Investments 3 122 — — 125 Other Income (Deductions) 71 91 2 (144 ) 20 Non-Operating Pension and OPEB Credits (Costs) — 8 — — 8 Interest Expense (128 ) (49 ) (17 ) 144 (50 ) Income Tax Benefit (Expense) (26 ) 588 167 — 729 Net Income (Loss) $ 479 $ 482 $ 145 $ (627 ) $ 479 Comprehensive Income (Loss) $ 518 $ 529 $ 145 $ (674 ) $ 518 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 Year Ended December 31, 2017 Net Cash Provided By (Used In) Operating Activities $ (42 ) $ 1,185 $ 238 $ (55 ) $ 1,326 Net Cash Provided By (Used In) Investing Activities $ 506 $ (448 ) $ (525 ) $ (765 ) $ (1,232 ) Net Cash Provided By (Used In) Financing Activities $ (464 ) $ (736 ) $ 307 $ 820 $ (73 ) Power Guarantor Subsidiaries Other Subsidiaries Consolidating Adjustments Total Millions Year Ended December 31, 2016 Operating Revenues $ — $ 3,809 $ 173 $ (121 ) $ 3,861 Operating Expenses 8 3,796 161 (121 ) 3,844 Operating Income (Loss) (8 ) 13 12 — 17 Equity Earnings (Losses) of Subsidiaries 36 (3 ) 11 (33 ) 11 Net Gains (Losses) on Trust Investments 1 (7 ) — — (6 ) Other Income (Deductions) 52 60 — (89 ) 23 Non-Operating Pension and OPEB Credits (Costs) — (4 ) — — (4 ) Interest Expense (115 ) (40 ) (18 ) 89 (84 ) Income Tax Benefit (Expense) 52 (11 ) 20 — 61 Net Income (Loss) $ 18 $ 8 $ 25 $ (33 ) $ 18 Comprehensive Income (Loss) $ 47 $ 50 $ 25 $ (75 ) $ 47 Year Ended December 31, 2016 Net Cash Provided By (Used In) Operating Activities $ 97 $ 1,442 $ 323 $ (607 ) $ 1,255 Net Cash Provided By (Used In) Investing Activities $ 60 $ (707 ) $ (789 ) $ 289 $ (1,147 ) Net Cash Provided By (Used In) Financing Activities $ (157 ) $ (736 ) $ 466 $ 318 $ (109 )

Organization, Basis Of Presen_4

Organization, Basis Of Presentation And Summary Of Significant Accounting Policies (Narrative) (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Power [Member]
Organization Basis Of Presentation And Summary Of Significant Accounting Policies [Line Items]
Basis Adjustment	$ (986)	$ (986)
PSE&G [Member]
Organization Basis Of Presentation And Summary Of Significant Accounting Policies [Line Items]
Basis Adjustment	$ 986	$ 986

Organization, Basis Of Presen_5

Organization, Basis Of Presentation And Summary Of Significant Accounting Policies Organization, Basic of Presentation And Summary Of Significant Accounting Policies (Cash, Cash Equivalents and Restricted Cash) (Details) - USD ($) $ in Millions		Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Organization Basis Of Presentation And Summary Of Significant Accounting Policies [Line Items]
Cash and Cash Equivalents		$ 177	$ 313
Restricted Cash and Investments, Noncurrent		14	2
Restricted Cash and Investments, Current		8	0
Cash, Cash Equivalents and Restricted Cash		199	315	$ 426	$ 395
PSE&G [Member]
Organization Basis Of Presentation And Summary Of Significant Accounting Policies [Line Items]
Cash and Cash Equivalents		39	242
Restricted Cash and Investments, Noncurrent		14	2
Restricted Cash and Investments, Current		8	0
Cash, Cash Equivalents and Restricted Cash		61	244	393	199
Power [Member]
Organization Basis Of Presentation And Summary Of Significant Accounting Policies [Line Items]
Cash and Cash Equivalents		22	32
Restricted Cash and Investments, Noncurrent		0	0
Restricted Cash and Investments, Current		0	0
Cash, Cash Equivalents and Restricted Cash		22	32	$ 11	$ 12
Other [Member]
Organization Basis Of Presentation And Summary Of Significant Accounting Policies [Line Items]
Cash and Cash Equivalents	[1]	116	39
Restricted Cash and Investments, Noncurrent	[1]	0	0
Restricted Cash and Investments, Current	[1]	0	0
Cash, Cash Equivalents and Restricted Cash	[1]	$ 116	$ 39
[1]	Includes amounts applicable to PSEG (parent corporation), Energy Holdings and Services.

Organization, Basis Of Presen_6

Organization, Basis Of Presentation And Summary Of Significant Accounting Policies (Depreciation Rate Stated Percentage) (Details)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
General Plant Assets [Member] | Minimum [Member] | Power [Member]
Organization Basis Of Presentation And Summary Of Significant Accounting Policies [Line Items]
Estimated useful lives	3 years
General Plant Assets [Member] | Maximum [Member] | Power [Member]
Organization Basis Of Presentation And Summary Of Significant Accounting Policies [Line Items]
Estimated useful lives	20 years
Fossil Production [Member] | Minimum [Member] | Power [Member]
Organization Basis Of Presentation And Summary Of Significant Accounting Policies [Line Items]
Estimated useful lives	30 years
Fossil Production [Member] | Maximum [Member] | Power [Member]
Organization Basis Of Presentation And Summary Of Significant Accounting Policies [Line Items]
Estimated useful lives	67 years
Nuclear Production [Member] | Power [Member]
Organization Basis Of Presentation And Summary Of Significant Accounting Policies [Line Items]
Estimated useful lives	60 years
Pumped Storage Facilities [Member] | Power [Member]
Organization Basis Of Presentation And Summary Of Significant Accounting Policies [Line Items]
Estimated useful lives	76 years
Solar Assets [Member] | Power [Member]
Organization Basis Of Presentation And Summary Of Significant Accounting Policies [Line Items]
Estimated useful lives	25 years
Electric Transmission [Member] | PSE&G [Member]
Organization Basis Of Presentation And Summary Of Significant Accounting Policies [Line Items]
Depreciation Rate	2.42%	2.41%	2.39%
Electric Distribution [Member] | PSE&G [Member]
Organization Basis Of Presentation And Summary Of Significant Accounting Policies [Line Items]
Depreciation Rate	2.51%	2.51%	2.49%
Gas Distribution [Member] | PSE&G [Member]
Organization Basis Of Presentation And Summary Of Significant Accounting Policies [Line Items]
Depreciation Rate	1.61%	1.63%	1.63%

Organization, Basis Of Presen_7

Organization, Basis Of Presentation And Summary Of Significant Accounting Policies (Amounts And Average Rates Used To Calculate IDC Or AFUDC) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
PSE&G [Member]
Organization Basis Of Presentation And Summary Of Significant Accounting Policies [Line Items]
IDC/AFUDC	$ 70	$ 73	$ 66
Average Rate	7.74%	7.42%	7.81%
Power [Member]
Organization Basis Of Presentation And Summary Of Significant Accounting Policies [Line Items]
IDC/AFUDC	$ 67	$ 78	$ 54
Average Rate	4.60%	4.60%	4.87%

Recent Accounting Standards New

Recent Accounting Standards New Standards Adopted (Details) - USD ($) $ in Millions	3 Months Ended									6 Months Ended	12 Months Ended
	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Jun. 30, 2018	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Jan. 01, 2018	Dec. 31, 2015
New Accounting Pronouncement, Early Adoption [Line Items]
Operating Revenues		$ 2,468	$ 2,394		$ 2,818	$ 2,107	$ 2,254	$ 2,142	$ 2,591	$ 2,016	$ 9,696	$ 9,094	$ 8,966
Energy Costs											3,225	2,778	2,901
Operation and Maintenance											3,015	2,901	2,991
After-tax adjustment for new accounting standard						0						0		$ 176
Accumulated other comprehensive income (loss)		14,377				13,847					14,377	13,847	13,130		$ 13,067
Accounting Standards Update 2016-01 [Member]
New Accounting Pronouncement, Early Adoption [Line Items]
Pre-tax adjustment for new accounting standard														342
After-tax adjustment for new accounting standard														176
PSE&G [Member]
New Accounting Pronouncement, Early Adoption [Line Items]
Operating Revenues		1,645	1,595	$ 1,386	1,845	1,575	1,530	1,393	1,826		6,471	6,324	6,303
Energy Costs											2,520	2,421	2,644
Operation and Maintenance											1,575	1,458	1,465
Accumulated other comprehensive income (loss)		10,900				9,834					10,900	9,834	8,712		7,573
PSE&G [Member] | Accounting Standard Update 2017-07 [Member]
New Accounting Pronouncement, Early Adoption [Line Items]
Estimated Change in Expense related to new presentation of pension and OPEB costs											58
Prior Period Reclassification Adjustment												8	15
PSE&G [Member] | Accounting Standards Update 2018-02 [Member]
New Accounting Pronouncement, Early Adoption [Line Items]
Operating Revenues											81
Accumulated other comprehensive income (loss)		81									81
Power [Member]
New Accounting Pronouncement, Early Adoption [Line Items]
Operating Revenues		1,108	$ 868	$ 767	$ 1,403	827	$ 846	$ 918	$ 1,269		4,146	3,860	3,861
Energy Costs											2,197	1,913	1,824
Operation and Maintenance											999	1,046	1,139
After-tax adjustment for new accounting standard						0						0		$ 175
Accumulated other comprehensive income (loss)		5,960				$ 5,967					5,960	5,967	5,799		$ 6,002
Power [Member] | Accounting Standard Update 2017-07 [Member]
New Accounting Pronouncement, Early Adoption [Line Items]
Prior Period Reclassification Adjustment												(8)	4
Power [Member] | Accounting Standards Update 2018-02 [Member]
New Accounting Pronouncement, Early Adoption [Line Items]
Operating Revenues											69
Accumulated other comprehensive income (loss)		$ 69									$ 69
Subsequent Event [Member] | Accounting Standards Update 2016-02 [Member]
New Accounting Pronouncement, Early Adoption [Line Items]
Estimated Change in Expense related to new presentation of pension and OPEB costs	$ 280
Subsequent Event [Member] | PSE&G [Member] | Accounting Standards Update 2016-02 [Member]
New Accounting Pronouncement, Early Adoption [Line Items]
Estimated Change in Expense related to new presentation of pension and OPEB costs	100
Subsequent Event [Member] | Power [Member] | Accounting Standards Update 2016-02 [Member]
New Accounting Pronouncement, Early Adoption [Line Items]
Estimated Change in Expense related to new presentation of pension and OPEB costs	$ 50
Restatement Adjustment [Member] | PSE&G [Member] | Accounting Standards Update 2014-09 [Member]
New Accounting Pronouncement, Early Adoption [Line Items]
Operating Revenues												90	(82)
Energy Costs												58	77
Operation and Maintenance												32	5
Restatement Adjustment [Member] | Power [Member] | Accounting Standards Update 2014-09 [Member]
New Accounting Pronouncement, Early Adoption [Line Items]
Operating Revenues												70	162
Energy Costs												$ (70)	$ (162)

Revenues Revenues (Details)

Revenues Revenues (Details) $ in Millions		3 Months Ended							6 Months Ended	12 Months Ended
		Dec. 31, 2018USD ($)$ / mwdMW	Sep. 30, 2018USD ($)	Mar. 31, 2018USD ($)	Dec. 31, 2017USD ($)	Sep. 30, 2017USD ($)	Jun. 30, 2017USD ($)	Mar. 31, 2017USD ($)	Jun. 30, 2018USD ($)	Dec. 31, 2018USD ($)$ / mwdMW	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)
Revenues [Abstract]
Loss on Lease Investments included in Revenues										$ 8
Loss on Lease Investments included in Revenues										20	$ 77	$ 147
Revenue from Contract with Customer, Including Assessed Tax										9,337	8,347	8,174
Revenues Unrelated to Contracts with Customers	[1]									359	747	792
Operating Revenues		$ 2,468	$ 2,394	$ 2,818	$ 2,107	$ 2,254	$ 2,142	$ 2,591	$ 2,016	9,696	9,094	8,966
PSE&G [Member]
Revenue from Contract with Customer, Including Assessed Tax										6,398	6,259	6,285
Revenues Unrelated to Contracts with Customers	[1]									73	65	18
Operating Revenues										6,471	6,324	6,303
Power [Member]
Revenue from Contract with Customer, Including Assessed Tax										3,899	3,133	2,975
Revenues Unrelated to Contracts with Customers	[1]									247	727	886
Operating Revenues										4,146	3,860	3,861
Revenue, remaining performance obligation, amount		170								170
Other [Member]
Revenue from Contract with Customer, Including Assessed Tax										532	511	482
Revenues Unrelated to Contracts with Customers	[1]									39	(45)	(112)
Operating Revenues										571	466	370
Eliminations [Member]
Revenue from Contract with Customer, Including Assessed Tax										(1,492)	(1,556)	(1,568)
Revenues Unrelated to Contracts with Customers	[1]									0	0	0
Operating Revenues										(1,492)	(1,556)	(1,568)
LIPA OSA contract fixed component [Member] | Other [Member]
Revenue, remaining performance obligation, amount		64								64
Electric Distribution Contracts [Member]
Revenue from Contract with Customer, Including Assessed Tax										3,131	3,088	3,327
Electric Distribution Contracts [Member] | PSE&G [Member]
Revenue from Contract with Customer, Including Assessed Tax										3,131	3,088	3,327
Electric Distribution Contracts [Member] | Power [Member]
Revenue from Contract with Customer, Including Assessed Tax										0	0	0
Electric Distribution Contracts [Member] | Other [Member]
Revenue from Contract with Customer, Including Assessed Tax										0	0	0
Electric Distribution Contracts [Member] | Eliminations [Member]
Revenue from Contract with Customer, Including Assessed Tax										0	0	0
Gas Distribution Contracts [Member]
Revenue from Contract with Customer, Including Assessed Tax										1,738	1,670	1,560
Gas Distribution Contracts [Member] | PSE&G [Member]
Revenue from Contract with Customer, Including Assessed Tax										1,756	1,684	1,582
Gas Distribution Contracts [Member] | Power [Member]
Revenue from Contract with Customer, Including Assessed Tax										0	0	0
Gas Distribution Contracts [Member] | Other [Member]
Revenue from Contract with Customer, Including Assessed Tax										0	0	0
Gas Distribution Contracts [Member] | Eliminations [Member]
Revenue from Contract with Customer, Including Assessed Tax										(18)	(14)	(22)
Transmission [Member]
Revenue from Contract with Customer, Including Assessed Tax										1,236	1,222	1,084
Transmission [Member] | PSE&G [Member]
Revenue from Contract with Customer, Including Assessed Tax										1,236	1,222	1,084
Transmission [Member] | Power [Member]
Revenue from Contract with Customer, Including Assessed Tax										0	0	0
Transmission [Member] | Other [Member]
Revenue from Contract with Customer, Including Assessed Tax										0	0	0
Transmission [Member] | Eliminations [Member]
Revenue from Contract with Customer, Including Assessed Tax										0	0	0
Other Contract Revenues [Member]
Revenue from Contract with Customer, Including Assessed Tax	[2]									847	814	805
Other Contract Revenues [Member] | PSE&G [Member]
Revenue from Contract with Customer, Including Assessed Tax	[2]									275	265	292
Other Contract Revenues [Member] | Power [Member]
Revenue from Contract with Customer, Including Assessed Tax	[2]									44	42	35
Other Contract Revenues [Member] | Other [Member]
Revenue from Contract with Customer, Including Assessed Tax	[2]									532	511	482
Other Contract Revenues [Member] | Eliminations [Member]
Revenue from Contract with Customer, Including Assessed Tax	[2]									(4)	(4)	(4)
LIPA OSA contract incentive component [Member] | Other [Member]
Revenue, remaining performance obligation, amount		$ 10								10
ISO New England [Member] | Electricity and Related Products [Member]
Revenue from Contract with Customer, Including Assessed Tax										92	39	55
ISO New England [Member] | Electricity and Related Products [Member] | PSE&G [Member]
Revenue from Contract with Customer, Including Assessed Tax										0	0	0
ISO New England [Member] | Electricity and Related Products [Member] | Power [Member]
Revenue from Contract with Customer, Including Assessed Tax										92	39	55
ISO New England [Member] | Electricity and Related Products [Member] | Other [Member]
Revenue from Contract with Customer, Including Assessed Tax										0	0	0
ISO New England [Member] | Electricity and Related Products [Member] | Eliminations [Member]
Revenue from Contract with Customer, Including Assessed Tax										0	0	0
NY ISO [Member] | Electricity and Related Products [Member]
Revenue from Contract with Customer, Including Assessed Tax										209	181	169
NY ISO [Member] | Electricity and Related Products [Member] | PSE&G [Member]
Revenue from Contract with Customer, Including Assessed Tax										0	0	0
NY ISO [Member] | Electricity and Related Products [Member] | Power [Member]
Revenue from Contract with Customer, Including Assessed Tax										209	181	169
NY ISO [Member] | Electricity and Related Products [Member] | Other [Member]
Revenue from Contract with Customer, Including Assessed Tax										0	0	0
NY ISO [Member] | Electricity and Related Products [Member] | Eliminations [Member]
Revenue from Contract with Customer, Including Assessed Tax										0	0	0
Third Party Sales [Member] | Natural Gas [Member]
Revenue from Contract with Customer, Including Assessed Tax										151	134	114
Third Party Sales [Member] | Natural Gas [Member] | PSE&G [Member]
Revenue from Contract with Customer, Including Assessed Tax										0	0	0
Third Party Sales [Member] | Natural Gas [Member] | Power [Member]
Revenue from Contract with Customer, Including Assessed Tax										151	134	114
Third Party Sales [Member] | Natural Gas [Member] | Other [Member]
Revenue from Contract with Customer, Including Assessed Tax										0	0	0
Third Party Sales [Member] | Natural Gas [Member] | Eliminations [Member]
Revenue from Contract with Customer, Including Assessed Tax										0	0	0
Third Party Sales [Member] | PJM [Member] | Electricity and Related Products [Member]
Revenue from Contract with Customer, Including Assessed Tax										1,933	1,199	1,060
Third Party Sales [Member] | PJM [Member] | Electricity and Related Products [Member] | PSE&G [Member]
Revenue from Contract with Customer, Including Assessed Tax										0	0	0
Third Party Sales [Member] | PJM [Member] | Electricity and Related Products [Member] | Power [Member]
Revenue from Contract with Customer, Including Assessed Tax										1,933	1,199	1,060
Third Party Sales [Member] | PJM [Member] | Electricity and Related Products [Member] | Other [Member]
Revenue from Contract with Customer, Including Assessed Tax										0	0	0
Third Party Sales [Member] | PJM [Member] | Electricity and Related Products [Member] | Eliminations [Member]
Revenue from Contract with Customer, Including Assessed Tax										0	0	0
Affiliated Entity [Member] | Natural Gas [Member]
Revenue from Contract with Customer, Including Assessed Tax										0	0	0
Affiliated Entity [Member] | Natural Gas [Member] | PSE&G [Member]
Revenue from Contract with Customer, Including Assessed Tax										0	0	0
Affiliated Entity [Member] | Natural Gas [Member] | Power [Member]
Revenue from Contract with Customer, Including Assessed Tax										861	804	737
Affiliated Entity [Member] | Natural Gas [Member] | Other [Member]
Revenue from Contract with Customer, Including Assessed Tax										0	0	0
Affiliated Entity [Member] | Natural Gas [Member] | Eliminations [Member]
Revenue from Contract with Customer, Including Assessed Tax										(861)	(804)	(737)
Affiliated Entity [Member] | PJM [Member] | Electricity and Related Products [Member]
Revenue from Contract with Customer, Including Assessed Tax										0	0	0
Affiliated Entity [Member] | PJM [Member] | Electricity and Related Products [Member] | PSE&G [Member]
Revenue from Contract with Customer, Including Assessed Tax										0	0	0
Affiliated Entity [Member] | PJM [Member] | Electricity and Related Products [Member] | Power [Member]
Revenue from Contract with Customer, Including Assessed Tax										609	734	805
Affiliated Entity [Member] | PJM [Member] | Electricity and Related Products [Member] | Other [Member]
Revenue from Contract with Customer, Including Assessed Tax										0	0	0
Affiliated Entity [Member] | PJM [Member] | Electricity and Related Products [Member] | Eliminations [Member]
Revenue from Contract with Customer, Including Assessed Tax										$ (609)	$ (734)	$ (805)
June 2018 to May 2019 [Member] | PJM [Member] | Power [Member]
Dollars Per Megawatt-Day | $ / mwd		205								205
Load (MW) | MW		9,200								9,200
June 2018 to May 2019 [Member] | ISO New England [Member] | Power [Member]
Dollars Per Megawatt-Day | $ / mwd		314								314
Load (MW) | MW		820								820
June 2019 to May 2020 [Member] | PJM [Member] | Power [Member]
Dollars Per Megawatt-Day | $ / mwd		116								116
Load (MW) | MW		8,900								8,900
June 2019 to May 2020 [Member] | ISO New England [Member] | Power [Member]
Dollars Per Megawatt-Day | $ / mwd		231								231
Load (MW) | MW		1,330								1,330
June 2020 to May 2021 [Member] | PJM [Member] | Power [Member]
Dollars Per Megawatt-Day | $ / mwd		170								170
Load (MW) | MW		8,100								8,100
June 2020 to May 2021 [Member] | ISO New England [Member] | Power [Member]
Dollars Per Megawatt-Day | $ / mwd		195								195
Load (MW) | MW		1,330								1,330
June 2021 to May 2022 [Member] | PJM [Member] | Power [Member]
Dollars Per Megawatt-Day | $ / mwd		178								178
Load (MW) | MW		7,700								7,700
June 2021 to May 2022 [Member] | ISO New England [Member] | Power [Member]
Dollars Per Megawatt-Day | $ / mwd		192								192
Load (MW) | MW		950								950
June 2022 to May 2023 [Member] | ISO New England [Member] | Power [Member]
Dollars Per Megawatt-Day | $ / mwd		231								231
Load (MW) | MW		480								480
June 2023 to May 2024 [Member] | ISO New England [Member] | Power [Member]
Dollars Per Megawatt-Day | $ / mwd		231								231
Load (MW) | MW		480								480
June 2024 to May 2025 [Member] | ISO New England [Member] | Power [Member]
Dollars Per Megawatt-Day | $ / mwd		231								231
Load (MW) | MW		480								480
June 2025 to May 2026 [Member] | ISO New England [Member] | Power [Member]
Dollars Per Megawatt-Day | $ / mwd		231								231
Load (MW) | MW		480								480
[1]	Includes primarily alternative revenues at PSE&G, derivative contracts at Power, and lease contracts in Other. For the years ended December 31, 2018, 2017 and 2016, Other includes losses of $8 million, $77 million and $147 million, respectively, related to Energy Holdings’ investments in leases. For additional information, see Note 8. Long-Term Investments.
[2]	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.

Early Plant Retirements Early_3

Early Plant Retirements Early Plant Retirements (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Restructuring Cost and Reserve [Line Items]
Total Assets		$ 45,326	$ 42,716	$ 40,070
Asset Retirement Obligations, Noncurrent		1,063	1,024
Gain on Sale of Hudson and Mercer		54	0	0
Power [Member]
Restructuring Cost and Reserve [Line Items]
Total Assets		12,594	12,418
Asset Retirement Obligations, Noncurrent		758	810
Gain on Sale of Hudson and Mercer		54	0	0
Power [Member] | Energy Costs [Member]
Restructuring Cost and Reserve [Line Items]
Coal Inventory Lower of Cost or Market Adjustments and Capacity Penalties		3	15	62
Power [Member] | Operation and Maintenance Expense [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring Charges			23	53
Power [Member] | Depreciation And Amortization [Member]
Restructuring Cost and Reserve [Line Items]
Depreciation, including Asset Retirement Costs			$ 964	$ 571
Nuclear Support Facilities [Member]
Restructuring Cost and Reserve [Line Items]
Public Utilities, Inventory	[1]	0
Nuclear Production, Net of Accumulated Depreciation	[1]	197
Nuclear Fuel, Net of Accumulated Depreciation	[1]	0
Public Utilities, Property, Plant and Equipment, Construction Work in Progress	[1]	5
Total Assets	[1]	202
Asset Retirement Obligations, Noncurrent	[1]	0
Liabilities	[1]	0
Net Assets	[1]	202
Peach Bottom [Member]
Restructuring Cost and Reserve [Line Items]
Public Utilities, Inventory		41
Nuclear Production, Net of Accumulated Depreciation		777
Nuclear Fuel, Net of Accumulated Depreciation		148
Public Utilities, Property, Plant and Equipment, Construction Work in Progress		20
Total Assets		986
Asset Retirement Obligations, Noncurrent		215
Liabilities		215
Net Assets		$ 771
Jointly Owned Utility Plant, Proportionate Ownership Share		50.00%
Peach Bottom [Member] | Power [Member]
Restructuring Cost and Reserve [Line Items]
Jointly Owned Utility Plant, Proportionate Ownership Share		50.00%
Salem [Member]
Restructuring Cost and Reserve [Line Items]
Public Utilities, Inventory		$ 65
Nuclear Production, Net of Accumulated Depreciation		626
Nuclear Fuel, Net of Accumulated Depreciation		110
Public Utilities, Property, Plant and Equipment, Construction Work in Progress		132
Total Assets		933
Asset Retirement Obligations, Noncurrent		240
Liabilities		240
Net Assets		$ 693
Jointly Owned Utility Plant, Proportionate Ownership Share		57.00%
Salem [Member] | Power [Member]
Restructuring Cost and Reserve [Line Items]
Jointly Owned Utility Plant, Proportionate Ownership Share		57.00%
Hope Creek [Member]
Restructuring Cost and Reserve [Line Items]
Public Utilities, Inventory		$ 84
Nuclear Production, Net of Accumulated Depreciation		635
Nuclear Fuel, Net of Accumulated Depreciation		139
Public Utilities, Property, Plant and Equipment, Construction Work in Progress		131
Total Assets		989
Asset Retirement Obligations, Noncurrent		253
Liabilities		253
Net Assets		$ 736
Jointly Owned Utility Plant, Proportionate Ownership Share		100.00%
[1]	Includes Hope Creek’s and Salem’s shared support facilities and other nuclear development capital.

Variable Interest Entities (V_2

Variable Interest Entities (VIEs) (Detail) - USD ($) $ in Millions	3 Months Ended								6 Months Ended	12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Jun. 30, 2018	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Variable Interest Entity [Line Items]
Operating Revenues	$ 2,468	$ 2,394		$ 2,818	$ 2,107	$ 2,254	$ 2,142	$ 2,591	$ 2,016	$ 9,696	$ 9,094	$ 8,966
Operation and Maintenance										3,015	2,901	2,991
PSE&G [Member]
Variable Interest Entity [Line Items]
Operating Revenues	$ 1,645	$ 1,595	$ 1,386	$ 1,845	$ 1,575	$ 1,530	$ 1,393	$ 1,826		6,471	6,324	6,303
Operation and Maintenance										1,575	1,458	1,465
Long Island ServCo [Member]
Variable Interest Entity [Line Items]
Operating Revenues										458	438	410
Operation and Maintenance										$ 458	$ 438	$ 410

Property, Plant And Equipment_3

Property, Plant And Equipment And Jointly-Owned Facilities (Schedule Of Property, Plant And Equipment) (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Public Utility, Property, Plant and Equipment [Line Items]
Total Transmission and Distribution	$ 30,628	$ 28,249
Total Generation	12,744	12,250
Other	829	732
Total	44,201	41,231
PSE&G [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Total Transmission and Distribution	30,628	28,249
Total Generation	623	593
Other	382	275
Total	31,633	29,117
Power [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Total Transmission and Distribution	0	0
Total Generation	12,121	11,657
Other	103	98
Total	12,224	11,755
Other [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Total Transmission and Distribution	0	0
Total Generation	0	0
Other	344	359
Total	344	359
Electric Transmission [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Total Transmission and Distribution	11,991	10,425
Electric Transmission [Member] | PSE&G [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Total Transmission and Distribution	11,991	10,425
Electric Transmission [Member] | Power [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Total Transmission and Distribution	0	0
Electric Transmission [Member] | Other [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Total Transmission and Distribution	0	0
Electric Distribution [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Total Transmission and Distribution	8,989	8,455
Electric Distribution [Member] | PSE&G [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Total Transmission and Distribution	8,989	8,455
Electric Distribution [Member] | Power [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Total Transmission and Distribution	0	0
Electric Distribution [Member] | Other [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Total Transmission and Distribution	0	0
Gas Distribution [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Total Transmission and Distribution	7,854	7,122
Gas Distribution [Member] | PSE&G [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Total Transmission and Distribution	7,854	7,122
Gas Distribution [Member] | Power [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Total Transmission and Distribution	0	0
Gas Distribution [Member] | Other [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Total Transmission and Distribution	0	0
Construction Work In Progress [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Total Transmission and Distribution	1,170	1,735
Total Generation	1,011	2,339
Construction Work In Progress [Member] | PSE&G [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Total Transmission and Distribution	1,170	1,735
Total Generation	0	0
Construction Work In Progress [Member] | Power [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Total Transmission and Distribution	0	0
Total Generation	1,011	2,339
Construction Work In Progress [Member] | Other [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Total Transmission and Distribution	0	0
Total Generation	0	0
Other Plant [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Total Transmission and Distribution	624	512
Other Plant [Member] | PSE&G [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Total Transmission and Distribution	624	512
Other Plant [Member] | Power [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Total Transmission and Distribution	0	0
Other Plant [Member] | Other [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Total Transmission and Distribution	0	0
Fossil Production [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Total Generation	6,541	4,923
Fossil Production [Member] | PSE&G [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Total Generation	0	0
Fossil Production [Member] | Power [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Total Generation	6,541	4,923
Fossil Production [Member] | Other [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Total Generation	0	0
Nuclear Production [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Total Generation	2,971	2,893
Nuclear Production [Member] | PSE&G [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Total Generation	0	0
Nuclear Production [Member] | Power [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Total Generation	2,971	2,893
Nuclear Production [Member] | Other [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Total Generation	0	0
Nuclear Fuel In Service [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Total Generation	765	745
Nuclear Fuel In Service [Member] | PSE&G [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Total Generation	0	0
Nuclear Fuel In Service [Member] | Power [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Total Generation	765	745
Nuclear Fuel In Service [Member] | Other [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Total Generation	0	0
Other Production-Solar [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Total Generation	1,456	1,350
Other Production-Solar [Member] | PSE&G [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Total Generation	623	593
Other Production-Solar [Member] | Power [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Total Generation	833	757
Other Production-Solar [Member] | Other [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Total Generation	$ 0	$ 0

Property, Plant And Equipment_4

Property, Plant And Equipment And Jointly-Owned Facilities (Schedule Of Jointly-Owned Facilities) (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Conemaugh [Member] | Power [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Ownership Interest	23.00%
Plant	$ 417	$ 408
Accumulated Depreciation	$ 192	178
Keystone [Member] | Power [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Ownership Interest	23.00%
Plant	$ 416	409
Accumulated Depreciation	$ 200	187
Peach Bottom [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Ownership Interest	50.00%
Peach Bottom [Member] | Power [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Ownership Interest	50.00%
Plant	$ 1,334	1,328
Accumulated Depreciation	$ 389	348
Salem [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Ownership Interest	57.00%
Salem [Member] | Power [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Ownership Interest	57.00%
Plant	$ 1,196	1,147
Accumulated Depreciation	333	277
Nuclear Support Facilities [Member] | Power [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Plant	244	239
Accumulated Depreciation	$ 95	81
Yards Creek [Member] | Power [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Ownership Interest	50.00%
Plant	$ 48	44
Accumulated Depreciation	$ 26	26
Merrill Creek Reservoir [Member] | Power [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Ownership Interest	14.00%
Plant	$ 1	1
Accumulated Depreciation	0	0
Transmission Facilities [Member] | PSE&G [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Plant	162	162
Accumulated Depreciation	$ 58	$ 58

Regulatory Assets And Liabili_3

Regulatory Assets And Liabilities (Schedule Of Regulatory Assets and Liabilities) (Details) $ in Millions	1 Months Ended
	Jan. 31, 2019USD ($)	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)
Regulatory Assets And Liabilities [Line Items]
Regulatory Assets, Current		$ 389	$ 211
Regulatory Assets, Noncurrent		3,399	3,222
Regulatory Liability, Current		311	47
Regulatory Liabilities, Noncurrent		$ 3,221	2,948
PSE&G [Member]
Regulatory Assets And Liabilities [Line Items]
Current BGSS rate per therm		0.37
Proposed BGSS rate per therm		0.35
True-up adjustment for Transmission Formula Rate Revenues		$ 27
Regulatory Assets, Current		389	211
Regulatory Assets, Noncurrent		3,399	3,222
Total Regulatory Assets		3,788	3,433
Regulatory Liability, Current		311	47
Regulatory Liabilities, Noncurrent		3,221	2,948
Total Regulatory Liabilities		3,532	2,995
Excess Deferred Income Taxes [Member] | PSE&G [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory Liability, Current		299	0
Regulatory Liabilities, Noncurrent		3,170	2,868
Reduction in Deferred Tax Liabilities			2,100
Gas Margin Adjustment Clause [Member] | PSE&G [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory Liability, Current		8	12
Overrecovered Gas and Electric Costs - BGSS and BGS [Member] | PSE&G [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory Liability, Current		0	30
Electric and Gas Cost Of Removal [Member] | PSE&G [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory Liabilities, Noncurrent		51	80
Other [Member] | PSE&G [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory Liability, Current		4	5
New Jersey Clean Energy Program [Member] | PSE&G [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory Assets, Current		143	128
Weather Normalization Clause [Member] | PSE&G [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory Assets, Current		2	40
Solar and EE Recovery Charge formerly RRC and currently Green Program Recovery Charges (GPRC) [Member] | PSE&G [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory Assets, Current		34	8
Regulatory Assets, Noncurrent		95	98
Pension and Other Postretirement Benefit Costs [Member] | PSE&G [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory Assets, Noncurrent		1,090	1,488
Deferred Income Taxes [Member] | PSE&G [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory Assets, Noncurrent		896	282
Manufactured Gas Plant (MGP) Remediation Costs [Member] | PSE&G [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory Assets, Noncurrent		321	358
Storm Damage and Other [Member] | PSE&G [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory Assets, Current		56	0
Regulatory Assets, Noncurrent		214	241
Remediation Adjustment Charge (Other SBC) [Member] | PSE&G [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory Assets, Noncurrent		175	172
Conditional Asset Retirement Obligation [Member] | PSE&G [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory Assets, Noncurrent		166	162
Electric and Gas Cost Of Removal [Member] | PSE&G [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory Assets, Noncurrent		223	199
Unamortized Loss On Reacquired Debt And Debt Expense [Member] | PSE&G [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory Assets, Noncurrent		49	55
Other [Member] | PSE&G [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory Assets, Current		39	12
Regulatory Assets, Noncurrent		139	137
Underrecovered Electric Costs Basic Generation Service [Member] | PSE&G [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory Assets, Current		115	23
Overrecovered Gas and Electric Costs - BGSS and BGS [Member] | PSE&G [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory Assets, Noncurrent		$ 31	$ 30
Subsequent Event [Member] | Transmission Formula Rate [Member] | PSE&G [Member]
Regulatory Assets And Liabilities [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount	$ (54)

Regulatory Assets And Liabili_4

Regulatory Assets And Liabilities (Significant Orders and Pending Filings) (Details) $ in Millions	1 Months Ended					2 Months Ended	12 Months Ended
	Jan. 31, 2019USD ($)	Dec. 31, 2018USD ($)	Oct. 31, 2018USD ($)	Aug. 31, 2018USD ($)	Apr. 30, 2018USD ($)	Feb. 28, 2018USD ($)	Dec. 31, 2018USD ($)	Dec. 31, 2017
Regulatory Assets And Liabilities [Line Items]
Maximum U.S. Corporate Income Tax Rate							21.00%	35.00%
PSE&G [Member]
Regulatory Assets And Liabilities [Line Items]
Current BGSS rate per therm		0.37					0.37
Proposed BGSS rate per therm		0.35					0.35
True-up adjustment for Transmission Formula Rate Revenues		$ 27					$ 27
Distribution Base rates [Member] | PSE&G [Member]
Regulatory Assets And Liabilities [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount			$ 13
Public Utilities, Approved Rate Base			$ 9,500
Public Utilities, Approved Return on Equity, Percentage			9.60%
Public Utilities, Approved Equity Capital Structure, Percentage			54.00%
Revenue Subject to Refund [Member] | PSE&G [Member]
Regulatory Assets And Liabilities [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount			$ 28
Gas Distribution [Member] | PSE&G [Member]
Regulatory Assets And Liabilities [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount							43
Transmission related unprotected deferred taxes [Member] | PSE&G [Member]
Regulatory Assets And Liabilities [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount							114
Gas System Modernization Program [Member] | PSE&G [Member]
Regulatory Assets And Liabilities [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount		$ (21)
Electric Distribution [Member] | PSE&G [Member]
Regulatory Assets And Liabilities [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount							71
Weather Normalization Clause [Member] | PSE&G [Member]
Regulatory Assets And Liabilities [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount			(14)		$ (55)
Remediation Adjustment Charge (Other SBC) [Member] | PSE&G [Member]
Regulatory Assets And Liabilities [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount			(63)
Electric Green Program Recovery [Member] | PSE&G [Member]
Regulatory Assets And Liabilities [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount							(65)
Gas Green Program Recovery [Member] | PSE&G [Member]
Regulatory Assets And Liabilities [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount							(6)
BGSS [Member] | PSE&G [Member]
Regulatory Assets And Liabilities [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount							26
Subsequent Event [Member] | Transmission Formula Rate [Member] | PSE&G [Member]
Regulatory Assets And Liabilities [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount	$ 54
Subsequent Event [Member] | Remediation Adjustment Charge (Other SBC) [Member] | PSE&G [Member]
Regulatory Assets And Liabilities [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount	$ (73)
2017 to 2018 [Member] | Weather Normalization Clause [Member] | PSE&G [Member]
Regulatory Assets And Liabilities [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount			9
2015 to 2016 [Member] | Weather Normalization Clause [Member] | PSE&G [Member]
Regulatory Assets And Liabilities [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount					(24)
2016 to 2017 [Member] | Weather Normalization Clause [Member] | PSE&G [Member]
Regulatory Assets And Liabilities [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount			(23)		$ (31)
Solar or EE Recovery Charge (RRC) [Member] | Gas Distribution [Member] | PSE&G [Member]
Regulatory Assets And Liabilities [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount			(15)
Solar or EE Recovery Charge (RRC) [Member] | Electric Distribution [Member] | PSE&G [Member]
Regulatory Assets And Liabilities [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount			(58)
Energy Strong program [Member] | Gas Distribution [Member] | PSE&G [Member]
Regulatory Assets And Liabilities [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount				$ (0.1)
Energy Strong program [Member] | Electric Distribution [Member] | PSE&G [Member]
Regulatory Assets And Liabilities [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount				$ (0.6)		$ (8)
Societal Benefits Charges Sbc [Member] | Gas Distribution [Member] | PSE&G [Member]
Regulatory Assets And Liabilities [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount							0.8
Societal Benefits Charges Sbc [Member] | Electric Distribution [Member] | PSE&G [Member]
Regulatory Assets And Liabilities [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount							$ (20)
Base Revenues [Member] | Distribution Base rates [Member] | PSE&G [Member]
Regulatory Assets And Liabilities [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount			(212)
Return of Tax Benefits [Member] | Distribution Base rates [Member] | PSE&G [Member]
Regulatory Assets And Liabilities [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount			$ 225

Long-Term Investments (Schedule

Long-Term Investments (Schedule Of Long Term Investments) (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Long-Term Investments [Line Items]
Pretax gain on REMA restructuring			$ 12
Total Long-Term Investments			896	$ 932
Dividends in equity method investments			16	18	$ 18
Provision for Loan and Lease Losses				7	137
Financing Receivable, Allowance for Credit Losses, Write-downs			20	77	$ 147
After tax gain on REMA restructuring			9
Expected claim proceeds			31.5
REMA Funded credit support			36
Power [Member]
Long-Term Investments [Line Items]
Total Long-Term Investments			86	87
PSE&G [Member]
Long-Term Investments [Line Items]
Total Long-Term Investments			270	280
Life Insurance And Supplemental Benefits [Member] | PSE&G [Member]
Long-Term Investments [Line Items]
Total Long-Term Investments			121	130
Solar Loan Investments [Member] | PSE&G [Member]
Long-Term Investments [Line Items]
Total Long-Term Investments			149	150
Lease Investments [Member] | Energy Holdings [Member]
Long-Term Investments [Line Items]
Total Long-Term Investments			540	565
Partnerships And Corporate Joint Ventures [Member] | Power [Member]
Long-Term Investments [Line Items]
Total Long-Term Investments	[1]		$ 86	$ 87
Subsequent Event [Member]
Long-Term Investments [Line Items]
Expected tax payment for REMA restructuring		$ 120
[1]	During the three years ended December 31, 2018, 2017 and 2016, dividends from these investments were $16 million, $18 million and $18 million, respectively.

Long-Term Investments (Schedu_2

Long-Term Investments (Schedule Of Net Investment In Leveraged Leases) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Schedule of Investments [Line Items]
Maximum U.S. Corporate Income Tax Rate	21.00%	35.00%
Lease Receivables (net of Non-Recourse Debt)	$ 504	$ 546
Estimated Residual Value of Leased Assets	326	326
Total Investment in Rental Receivables	830	872
Unearned and Deferred Income	(290)	(307)
Gross Investment in Leases	540	565
Deferred Tax Liabilities	(354)	(480)
Net Investments in Leases	$ 186	$ 85

Long-Term Investments (Schedu_3

Long-Term Investments (Schedule Of Pre-Tax Income And Income Tax Effects Related To Investments In Leveraged Leases) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Long-term Investments [Abstract]
Pre-Tax Income (Loss) from Leases	$ 17	$ (69)	$ (135)
Income Tax Expense (Benefit) on Income from Leases	$ 6	$ (26)	$ (51)

Long-Term Investments (Equity M

Long-Term Investments (Equity Method Investments) (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2018	Dec. 31, 2017
Long-Term Investments [Line Items]
Long-Term Investments		$ 896	$ 932
Keystone [Member]
Long-Term Investments [Line Items]
Location of the affiliated companies, equity method investments		PA
Owned percentage		23.00%
Conemaugh [Member]
Long-Term Investments [Line Items]
Location of the affiliated companies, equity method investments		PA
Owned percentage		23.00%
Kalaeloa [Member]
Long-Term Investments [Line Items]
Location of the affiliated companies, equity method investments		HI
Owned percentage		50.00%
Power [Member]
Long-Term Investments [Line Items]
Long-Term Investments		$ 86	87
Power [Member] | Partnerships And Corporate Joint Ventures [Member]
Long-Term Investments [Line Items]
Long-Term Investments	[1]	86	87
Power [Member] | Partnerships And Corporate Joint Ventures [Member] | Keystone [Member]
Long-Term Investments [Line Items]
Long-Term Investments		9	8
Power [Member] | Partnerships And Corporate Joint Ventures [Member] | Conemaugh [Member]
Long-Term Investments [Line Items]
Long-Term Investments		8	8
Power [Member] | Partnerships And Corporate Joint Ventures [Member] | Kalaeloa [Member]
Long-Term Investments [Line Items]
Long-Term Investments		$ 69	$ 71
[1]	During the three years ended December 31, 2018, 2017 and 2016, dividends from these investments were $16 million, $18 million and $18 million, respectively.

Financing Receivables (Schedule

Financing Receivables (Schedule Of Credit Risk Profile Based On Payment Activity) (Detail) - PSE&G [Member] - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Concentration Risk [Line Items]
Solar Loans	$ 173	$ 168
Current Portion of Solar Loans	(24)	(18)
Commercial/Industrial [Member]
Concentration Risk [Line Items]
Solar Loans	164	158
Residential [Member]
Concentration Risk [Line Items]
Solar Loans	9	10
Solar Loan Investments [Member]
Concentration Risk [Line Items]
Noncurrent Portion of Solar Loans	$ 149	$ 150

Financing Receivables (Schedu_2

Financing Receivables (Schedule Of Lease Receivables, Net Of Nonrecourse Debt, Associated With Leveraged Lease Portfolio Based On Counterparty Credit Rating) (Detail) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Guarantor Obligations [Line Items]
Lease Receivables, Net of Non-Recourse Debt	$ 504	$ 546
Energy Holdings [Member]
Guarantor Obligations [Line Items]
Lease Receivables, Net of Non-Recourse Debt	504
Energy Holdings [Member] | Counterparties' Credit Rating (S&P), AA [Member]
Guarantor Obligations [Line Items]
Lease Receivables, Net of Non-Recourse Debt	14
Energy Holdings [Member] | Counterparties' Credit Rating (S&P), BBB plus, BBB, BBB minus [Member]
Guarantor Obligations [Line Items]
Lease Receivables, Net of Non-Recourse Debt	316
Energy Holdings [Member] | Standard & Poor's, BB Rating [Member]
Guarantor Obligations [Line Items]
Lease Receivables, Net of Non-Recourse Debt	133
Energy Holdings [Member] | Not Rated [Member]
Guarantor Obligations [Line Items]
Lease Receivables, Net of Non-Recourse Debt	$ 41

Financing Receivables (Narrativ

Financing Receivables (Narrative) (Detail) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Financing Receivable, Recorded Investment [Line Items]
Net Investments in Leases	$ 186	$ 85
Lease investment with non-investment grade counterparties, gross	296
Lease investment with non-investment grade counterparties, net of deferred taxes	$ 10
Powerton Station [Member]
Financing Receivable, Recorded Investment [Line Items]
Lease Receivable Percent Owned	64.00%

Financing Receivables (Schedu_3

Financing Receivables (Schedule Of Assets Under Lease Receivables) (Detail) $ in Millions	12 Months Ended
	Dec. 31, 2018USD ($)MW
Powerton Station Units 5 And 6 [Member]
Financing Receivable, Recorded Investment [Line Items]
Lease Receivable, Asset Location	IL
Lease Receivable, Gross Investment | $	$ 133
Lease Receivable, % Owned	64.00%
Lease Receivable, Total, MW | MW	1,538
Lease Receivable, Asset, Fuel Type	Coal
Lease Receivable, Counterparties' S&P Credit Ratings	BB
Lease Receivable, Counterparty	NRG Energy, Inc.
Joliet Station Units 7 And 8 [Member]
Financing Receivable, Recorded Investment [Line Items]
Lease Receivable, Asset Location	IL
Lease Receivable, Gross Investment | $	$ 85
Lease Receivable, % Owned	64.00%
Lease Receivable, Total, MW | MW	1,036
Lease Receivable, Asset, Fuel Type	Gas
Lease Receivable, Counterparties' S&P Credit Ratings	BB
Lease Receivable, Counterparty	NRG Energy, Inc.
Shawville Station [Member]
Financing Receivable, Recorded Investment [Line Items]
Lease Receivable, Asset Location	PA
Lease Receivable, Gross Investment | $	$ 78
Lease Receivable, % Owned	100.00%
Lease Receivable, Total, MW | MW	596
Lease Receivable, Asset, Fuel Type	Gas
Lease Receivable, Counterparties' S&P Credit Ratings	NR
Lease Receivable, Counterparty	REMA (A)	[1]
[1]	REMA emerged from Chapter 11 of the U.S. Bankruptcy Code in December 2018. For additional information, see Note 8. Long-Term Investments.

Trust Investments (Fair Values

Trust Investments (Fair Values And Gross Unrealized Gains And Losses For The Securities) (Detail) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2018	Dec. 31, 2017
Nuclear Decommissioning Trust (NDT) Fund [Member]
Schedule of Trust Investments [Line Items]
Fair Value		$ 978
Rabbi Trust [Member]
Schedule of Trust Investments [Line Items]
Trust Investments, Continuous Unrealized Loss Position, Less than Twelve Months, Fair Value			$ 67
Trust Investments, Continuous Unrealized Loss Position, Less than 12 Months, Accumulated Loss			1
Trust Investments, Continuous Unrealized Loss Position, Twelve Months or Longer, Fair Value			34
Trust Investments, Continuous Unrealized Loss Position, 12 Months or Longer, Accumulated Loss			1
Cost		228
Gross Unrealized Gains		2
Gross Unrealized Losses		(6)
Fair Value		201
Cost			227
Gross Unrealized Gains			6
Gross Unrealized Losses			(2)
Fair Value		224	231
Rabbi Trust [Member] | Domestic Equity Securities [Member]
Schedule of Trust Investments [Line Items]
Cost		22
Gross Unrealized Gains		1
Gross Unrealized Losses		0
Fair Value		23
Cost			24
Gross Unrealized Gains			3
Gross Unrealized Losses			0
Fair Value			27
Rabbi Trust [Member] | International Equity Securities [Member]
Schedule of Trust Investments [Line Items]
Cost		0
Gross Unrealized Gains		0
Gross Unrealized Losses		0
Fair Value		0
Cost			0
Gross Unrealized Gains			0
Gross Unrealized Losses			0
Fair Value			0
Rabbi Trust [Member] | Equity Securities [Member]
Schedule of Trust Investments [Line Items]
Cost		22
Gross Unrealized Gains		1
Gross Unrealized Losses		0
Fair Value		23
Cost			24
Gross Unrealized Gains			3
Gross Unrealized Losses			0
Fair Value			27
Unrealized Gains (Losses) on Equity Securities still held		(2)
Rabbi Trust [Member] | Government Obligations [Member]
Schedule of Trust Investments [Line Items]
Trust Investments, Continuous Unrealized Loss Position, Less than Twelve Months, Fair Value	[1]		28
Trust Investments, Continuous Unrealized Loss Position, Less than 12 Months, Accumulated Loss	[1]		0
Trust Investments, Continuous Unrealized Loss Position, Twelve Months or Longer, Fair Value	[1]		25
Trust Investments, Continuous Unrealized Loss Position, 12 Months or Longer, Accumulated Loss	[1]		1
Cost		110
Gross Unrealized Gains		1
Gross Unrealized Losses		(2)
Fair Value		109
Cost			85
Gross Unrealized Gains			1
Gross Unrealized Losses			(1)
Fair Value			85
Rabbi Trust [Member] | Corporate Debt Securities [Member]
Schedule of Trust Investments [Line Items]
Trust Investments, Continuous Unrealized Loss Position, Less than Twelve Months, Fair Value	[2]		39
Trust Investments, Continuous Unrealized Loss Position, Less than 12 Months, Accumulated Loss	[2]		1
Trust Investments, Continuous Unrealized Loss Position, Twelve Months or Longer, Fair Value	[2]		9
Trust Investments, Continuous Unrealized Loss Position, 12 Months or Longer, Accumulated Loss	[2]		0
Cost		96
Gross Unrealized Gains		0
Gross Unrealized Losses		(4)
Fair Value		92
Cost			118
Gross Unrealized Gains			2
Gross Unrealized Losses			(1)
Fair Value			119
Rabbi Trust [Member] | Debt Securities [Member]
Schedule of Trust Investments [Line Items]
Other Comprehensive Income (Loss), Available-for-sale Securities Adjustment, Net of Tax, Portion Attributable to Parent		(4)
Trust Investments, Continuous Unrealized Loss Position, Less than Twelve Months, Fair Value			67
Trust Investments, Continuous Unrealized Loss Position, Less than 12 Months, Accumulated Loss			1
Trust Investments, Continuous Unrealized Loss Position, Twelve Months or Longer, Fair Value			34
Trust Investments, Continuous Unrealized Loss Position, 12 Months or Longer, Accumulated Loss			1
Cost		206
Gross Unrealized Gains		1
Gross Unrealized Losses		(6)
Fair Value		201
Cost			203
Gross Unrealized Gains			3
Gross Unrealized Losses			(2)
Fair Value			204
Power [Member] | Nuclear Decommissioning Trust (NDT) Fund [Member]
Schedule of Trust Investments [Line Items]
Trust Investments, Continuous Unrealized Loss Position, Less than Twelve Months, Fair Value			603
Trust Investments, Continuous Unrealized Loss Position, Less than 12 Months, Accumulated Loss			8
Trust Investments, Continuous Unrealized Loss Position, Twelve Months or Longer, Fair Value			120
Trust Investments, Continuous Unrealized Loss Position, 12 Months or Longer, Accumulated Loss			3
Cost		1,769
Gross Unrealized Gains		192
Gross Unrealized Losses		(83)
Fair Value		1,878
Cost			1,794
Gross Unrealized Gains			350
Gross Unrealized Losses			(11)
Fair Value			2,133
Power [Member] | Nuclear Decommissioning Trust (NDT) Fund [Member] | Domestic Equity Securities [Member]
Schedule of Trust Investments [Line Items]
Trust Investments, Continuous Unrealized Loss Position, Less than Twelve Months, Fair Value	[3]	147	40
Trust Investments, Continuous Unrealized Loss Position, Less than 12 Months, Accumulated Loss	[3]	26	2
Trust Investments, Continuous Unrealized Loss Position, Twelve Months or Longer, Fair Value	[3]	5	0
Trust Investments, Continuous Unrealized Loss Position, 12 Months or Longer, Accumulated Loss	[3]	3	0
Cost		447
Gross Unrealized Gains		153
Gross Unrealized Losses		(29)
Fair Value		571
Cost			497
Gross Unrealized Gains			245
Gross Unrealized Losses			(2)
Fair Value			740
Power [Member] | Nuclear Decommissioning Trust (NDT) Fund [Member] | International Equity Securities [Member]
Schedule of Trust Investments [Line Items]
Trust Investments, Continuous Unrealized Loss Position, Less than Twelve Months, Fair Value	[3]	131	29
Trust Investments, Continuous Unrealized Loss Position, Less than 12 Months, Accumulated Loss	[3]	28	3
Trust Investments, Continuous Unrealized Loss Position, Twelve Months or Longer, Fair Value	[3]	5	2
Trust Investments, Continuous Unrealized Loss Position, 12 Months or Longer, Accumulated Loss	[3]	2	0
Cost		323
Gross Unrealized Gains		36
Gross Unrealized Losses		(30)
Fair Value		329
Cost			311
Gross Unrealized Gains			99
Gross Unrealized Losses			(3)
Fair Value			407
Power [Member] | Nuclear Decommissioning Trust (NDT) Fund [Member] | Equity Securities [Member]
Schedule of Trust Investments [Line Items]
Trust Investments, Continuous Unrealized Loss Position, Less than Twelve Months, Fair Value	[3]	278	69
Trust Investments, Continuous Unrealized Loss Position, Less than 12 Months, Accumulated Loss	[3]	54	5
Trust Investments, Continuous Unrealized Loss Position, Twelve Months or Longer, Fair Value	[3]	10	2
Trust Investments, Continuous Unrealized Loss Position, 12 Months or Longer, Accumulated Loss	[3]	5	0
Cost		770
Gross Unrealized Gains		189
Gross Unrealized Losses		(59)
Fair Value		900
Cost			808
Gross Unrealized Gains			344
Gross Unrealized Losses			(5)
Fair Value			1,147
Unrealized Gains (Losses) on Equity Securities still held		(127)
Power [Member] | Nuclear Decommissioning Trust (NDT) Fund [Member] | Government Obligations [Member]
Schedule of Trust Investments [Line Items]
Trust Investments, Continuous Unrealized Loss Position, Less than Twelve Months, Fair Value	[4]		343
Trust Investments, Continuous Unrealized Loss Position, Less than 12 Months, Accumulated Loss	[4]		2
Trust Investments, Continuous Unrealized Loss Position, Twelve Months or Longer, Fair Value	[4]		91
Trust Investments, Continuous Unrealized Loss Position, 12 Months or Longer, Accumulated Loss	[4]		2
Cost		498
Gross Unrealized Gains		2
Gross Unrealized Losses		(9)
Fair Value		491
Cost			586
Gross Unrealized Gains			2
Gross Unrealized Losses			(4)
Fair Value			584
Power [Member] | Nuclear Decommissioning Trust (NDT) Fund [Member] | Corporate Debt Securities [Member]
Schedule of Trust Investments [Line Items]
Trust Investments, Continuous Unrealized Loss Position, Less than Twelve Months, Fair Value	[5]		191
Trust Investments, Continuous Unrealized Loss Position, Less than 12 Months, Accumulated Loss	[5]		1
Trust Investments, Continuous Unrealized Loss Position, Twelve Months or Longer, Fair Value	[5]		27
Trust Investments, Continuous Unrealized Loss Position, 12 Months or Longer, Accumulated Loss	[5]		1
Cost		501
Gross Unrealized Gains		1
Gross Unrealized Losses		(15)
Fair Value		487
Cost			400
Gross Unrealized Gains			4
Gross Unrealized Losses			(2)
Fair Value			402
Power [Member] | Nuclear Decommissioning Trust (NDT) Fund [Member] | Debt Securities [Member]
Schedule of Trust Investments [Line Items]
Other Comprehensive Income (Loss), Available-for-sale Securities Adjustment, Net of Tax, Portion Attributable to Parent		(12)
Trust Investments, Continuous Unrealized Loss Position, Less than Twelve Months, Fair Value			534
Trust Investments, Continuous Unrealized Loss Position, Less than 12 Months, Accumulated Loss			3
Trust Investments, Continuous Unrealized Loss Position, Twelve Months or Longer, Fair Value			118
Trust Investments, Continuous Unrealized Loss Position, 12 Months or Longer, Accumulated Loss			3
Cost		999
Gross Unrealized Gains		3
Gross Unrealized Losses		(24)
Fair Value		978
Cost			986
Gross Unrealized Gains			6
Gross Unrealized Losses			(6)
Fair Value			986
Power [Member] | Rabbi Trust [Member]
Schedule of Trust Investments [Line Items]
Fair Value		$ 56	$ 57
[1]	Debt Securities (Government)—Unrealized gains and losses on these securities are recorded in Accumulated Other Comprehensive Income (Loss). The unrealized losses on PSEG’s Rabbi Trust investments in U.S. Treasury obligations and Federal Agency mortgage-backed securities were caused by interest rate changes. These investments are guaranteed by the U.S. government or an agency of the U.S. government. PSEG also has investments in municipal bonds that are primarily in investment grade securities. It is not expected that these securities will settle for less than their amortized cost. Since PSEG does not intend to sell these securities nor will it be more-likely-than-not required to sell, PSEG does not consider these debt securities to be other-than-temporarily impaired as of December 31, 2018.
[2]	Debt Securities (Corporate)—Unrealized gains and losses on these securities are recorded in Accumulated Other Comprehensive Income (Loss). PSEG’s investments in corporate bonds are primarily in investment grade securities. It is not expected that these securities would settle for less than their amortized cost. Since PSEG does not intend to sell these securities nor will it be more-likely-than-not required to sell, PSEG does not consider these debt securities to be other-than-temporarily impaired as of December 31, 2018.
[3]	Equity Securities—Investments in marketable equity securities within the NDT Fund are primarily in common stocks within a broad range of industries and sectors. Effective January 1, 2018, unrealized gains and losses on these securities are recorded in Net Income.
[4]	Debt Securities (Government)—Unrealized gains and losses on these securities are recorded in Accumulated Other Comprehensive Income (Loss). The unrealized losses on Power’s NDT investments in U.S. Treasury obligations and Federal Agency mortgage-backed securities were caused by interest rate changes. These investments are guaranteed by the U.S. government or an agency of the U.S. government. Power also has investments in municipal bonds that are primarily in investment grade securities. It is not expected that these securities will settle for less than their amortized cost. Since Power does not intend to sell these securities nor will it be more-likely-than-not required to sell, Power does not consider these debt securities to be other-than-temporarily impaired as of December 31, 2018.
[5]	Debt Securities (Corporate)—Unrealized gains and losses on these securities are recorded in Accumulated Other Comprehensive Income (Loss). Power’s investments in corporate bonds are primarily in investment grade securities. It is not expected that these securities would settle for less than their amortized cost. Since Power does not intend to sell these securities nor will it be more-likely-than-not required to sell, Power does not consider these debt securities to be other-than-temporarily impaired as of December 31, 2018.

Trust Investments (Schedule Of

Trust Investments (Schedule Of Accounts Receivable And Accounts Payable) (Detail) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Rabbi Trust [Member]
Schedule of Trust Investments [Line Items]
Accounts Receivable	$ 2	$ 2
Accounts Payable	0	1
Nuclear Decommissioning Trust (NDT) Fund [Member] | Power [Member]
Schedule of Trust Investments [Line Items]
Accounts Receivable	17	24
Accounts Payable	$ 5	$ 74

Trust Investments (Value Of Sec

Trust Investments (Value Of Securities That Have Been In An Unrealized Loss Position For Less Than And Greater Than 12 Months) (Detail) - USD ($) $ in Millions		Dec. 31, 2018	Dec. 31, 2017
Nuclear Decommissioning Trust (NDT) Fund [Member] | Power [Member]
Schedule of Trust Investments [Line Items]
Fair Value, Less Than 12 Months			$ 603
Gross Unrealized Losses, Less than 12 Months			(8)
Fair Value, Greater Than 12 Months			120
Gross Unrealized Losses, Greater Than 12 Months			(3)
Fair Value, Less Than 12 Months		$ 479
Gross Unrealized Losses, Less than 12 Months		(59)
Fair Value, Greater Than 12 Months		549
Gross Unrealized Losses, Greater Than 12 Months		(24)
Nuclear Decommissioning Trust (NDT) Fund [Member] | Power [Member] | Domestic Equity Securities [Member]
Schedule of Trust Investments [Line Items]
Fair Value, Less Than 12 Months	[1]	147	40
Gross Unrealized Losses, Less than 12 Months	[1]	(26)	(2)
Fair Value, Greater Than 12 Months	[1]	5	0
Gross Unrealized Losses, Greater Than 12 Months	[1]	(3)	0
Nuclear Decommissioning Trust (NDT) Fund [Member] | Power [Member] | International Equity Securities [Member]
Schedule of Trust Investments [Line Items]
Fair Value, Less Than 12 Months	[1]	131	29
Gross Unrealized Losses, Less than 12 Months	[1]	(28)	(3)
Fair Value, Greater Than 12 Months	[1]	5	2
Gross Unrealized Losses, Greater Than 12 Months	[1]	(2)	0
Nuclear Decommissioning Trust (NDT) Fund [Member] | Power [Member] | Equity Securities [Member]
Schedule of Trust Investments [Line Items]
Fair Value, Less Than 12 Months	[1]	278	69
Gross Unrealized Losses, Less than 12 Months	[1]	(54)	(5)
Fair Value, Greater Than 12 Months	[1]	10	2
Gross Unrealized Losses, Greater Than 12 Months	[1]	(5)	0
Nuclear Decommissioning Trust (NDT) Fund [Member] | Power [Member] | Government Obligations [Member]
Schedule of Trust Investments [Line Items]
Fair Value, Less Than 12 Months	[2]		343
Gross Unrealized Losses, Less than 12 Months	[2]		(2)
Fair Value, Greater Than 12 Months	[2]		91
Gross Unrealized Losses, Greater Than 12 Months	[2]		(2)
Fair Value, Less Than 12 Months	[2]	51
Gross Unrealized Losses, Less than 12 Months	[2]	0
Fair Value, Greater Than 12 Months	[2]	317
Gross Unrealized Losses, Greater Than 12 Months	[2]	(9)
Nuclear Decommissioning Trust (NDT) Fund [Member] | Power [Member] | Corporate Debt Securities [Member]
Schedule of Trust Investments [Line Items]
Fair Value, Less Than 12 Months	[3]		191
Gross Unrealized Losses, Less than 12 Months	[3]		(1)
Fair Value, Greater Than 12 Months	[3]		27
Gross Unrealized Losses, Greater Than 12 Months	[3]		(1)
Fair Value, Less Than 12 Months	[3]	150
Gross Unrealized Losses, Less than 12 Months	[3]	(5)
Fair Value, Greater Than 12 Months	[3]	222
Gross Unrealized Losses, Greater Than 12 Months	[3]	(10)
Nuclear Decommissioning Trust (NDT) Fund [Member] | Power [Member] | Debt Securities [Member]
Schedule of Trust Investments [Line Items]
Fair Value, Less Than 12 Months			534
Gross Unrealized Losses, Less than 12 Months			(3)
Fair Value, Greater Than 12 Months			118
Gross Unrealized Losses, Greater Than 12 Months			(3)
Fair Value, Less Than 12 Months		201
Gross Unrealized Losses, Less than 12 Months		(5)
Fair Value, Greater Than 12 Months		539
Gross Unrealized Losses, Greater Than 12 Months		(19)
Rabbi Trust [Member]
Schedule of Trust Investments [Line Items]
Fair Value, Less Than 12 Months			67
Gross Unrealized Losses, Less than 12 Months			(1)
Fair Value, Greater Than 12 Months			34
Gross Unrealized Losses, Greater Than 12 Months			(1)
Fair Value, Less Than 12 Months		68
Gross Unrealized Losses, Less than 12 Months		(3)
Fair Value, Greater Than 12 Months		88
Gross Unrealized Losses, Greater Than 12 Months		(3)
Rabbi Trust [Member] | Government Obligations [Member]
Schedule of Trust Investments [Line Items]
Fair Value, Less Than 12 Months	[4]		28
Gross Unrealized Losses, Less than 12 Months	[4]		0
Fair Value, Greater Than 12 Months	[4]		25
Gross Unrealized Losses, Greater Than 12 Months	[4]		(1)
Fair Value, Less Than 12 Months	[2]	18
Gross Unrealized Losses, Less than 12 Months	[2]	0
Fair Value, Greater Than 12 Months	[2]	59
Gross Unrealized Losses, Greater Than 12 Months	[2]	(2)
Rabbi Trust [Member] | Corporate Debt Securities [Member]
Schedule of Trust Investments [Line Items]
Fair Value, Less Than 12 Months	[5]		39
Gross Unrealized Losses, Less than 12 Months	[5]		(1)
Fair Value, Greater Than 12 Months	[5]		9
Gross Unrealized Losses, Greater Than 12 Months	[5]		0
Fair Value, Less Than 12 Months	[3]	50
Gross Unrealized Losses, Less than 12 Months	[3]	(3)
Fair Value, Greater Than 12 Months	[3]	29
Gross Unrealized Losses, Greater Than 12 Months	[3]	(1)
Rabbi Trust [Member] | Debt Securities [Member]
Schedule of Trust Investments [Line Items]
Fair Value, Less Than 12 Months			67
Gross Unrealized Losses, Less than 12 Months			(1)
Fair Value, Greater Than 12 Months			34
Gross Unrealized Losses, Greater Than 12 Months			$ (1)
Fair Value, Less Than 12 Months		68
Gross Unrealized Losses, Less than 12 Months		(3)
Fair Value, Greater Than 12 Months		88
Gross Unrealized Losses, Greater Than 12 Months		$ (3)
[1]	Equity Securities—Investments in marketable equity securities within the NDT Fund are primarily in common stocks within a broad range of industries and sectors. Effective January 1, 2018, unrealized gains and losses on these securities are recorded in Net Income.
[2]	Debt Securities (Government)—Unrealized gains and losses on these securities are recorded in Accumulated Other Comprehensive Income (Loss). The unrealized losses on Power’s NDT investments in U.S. Treasury obligations and Federal Agency mortgage-backed securities were caused by interest rate changes. These investments are guaranteed by the U.S. government or an agency of the U.S. government. Power also has investments in municipal bonds that are primarily in investment grade securities. It is not expected that these securities will settle for less than their amortized cost. Since Power does not intend to sell these securities nor will it be more-likely-than-not required to sell, Power does not consider these debt securities to be other-than-temporarily impaired as of December 31, 2018.
[3]	Debt Securities (Corporate)—Unrealized gains and losses on these securities are recorded in Accumulated Other Comprehensive Income (Loss). Power’s investments in corporate bonds are primarily in investment grade securities. It is not expected that these securities would settle for less than their amortized cost. Since Power does not intend to sell these securities nor will it be more-likely-than-not required to sell, Power does not consider these debt securities to be other-than-temporarily impaired as of December 31, 2018.
[4]	Debt Securities (Government)—Unrealized gains and losses on these securities are recorded in Accumulated Other Comprehensive Income (Loss). The unrealized losses on PSEG’s Rabbi Trust investments in U.S. Treasury obligations and Federal Agency mortgage-backed securities were caused by interest rate changes. These investments are guaranteed by the U.S. government or an agency of the U.S. government. PSEG also has investments in municipal bonds that are primarily in investment grade securities. It is not expected that these securities will settle for less than their amortized cost. Since PSEG does not intend to sell these securities nor will it be more-likely-than-not required to sell, PSEG does not consider these debt securities to be other-than-temporarily impaired as of December 31, 2018.
[5]	Debt Securities (Corporate)—Unrealized gains and losses on these securities are recorded in Accumulated Other Comprehensive Income (Loss). PSEG’s investments in corporate bonds are primarily in investment grade securities. It is not expected that these securities would settle for less than their amortized cost. Since PSEG does not intend to sell these securities nor will it be more-likely-than-not required to sell, PSEG does not consider these debt securities to be other-than-temporarily impaired as of December 31, 2018.

Trust Investments (Proceeds Fro

Trust Investments (Proceeds From The Sales Of And The Net Realized Gains On Securities) (Detail) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2014
Schedule of Trust Investments [Line Items]
Net Gains (Losses) on Trust Investments		$ (143)	$ 134	$ (6)
Power [Member]
Schedule of Trust Investments [Line Items]
Net Gains (Losses) on Trust Investments		(140)	125	(6)
Nuclear Decommissioning Trust (NDT) Fund [Member] | Power [Member]
Schedule of Trust Investments [Line Items]
Proceeds from Sale and Maturity of Debt Securities, Available-for-sale	[1]	1,398	2,137		$ 711
Gross Realized Gains		121	157		53
Gross Realized Losses		(51)	(23)		(32)
Net Realized Gains (Losses)	[2]	70	134		21
Unrealized Gain (Loss) on Securities	[3]	(209)
Other than Temporary Impairment Losses, Investments		0	(12)	(28)
Net Gains (Losses) on Trust Investments		(139)	122	(7)
Rabbi Trust [Member]
Schedule of Trust Investments [Line Items]
Proceeds from Sale and Maturity of Debt Securities, Available-for-sale	[4]	103	182		113
Gross Realized Gains		2	17		6
Gross Realized Losses		(4)	(5)		(5)
Net Realized Gains (Losses)	[5]	(2)	12		$ 1
Unrealized Gain (Loss) on Securities	[6]	(2)
Net Gains (Losses) on Trust Investments		$ (4)	$ 12	$ 1
[1]	Includes activity in accounts related to the liquidation of funds being transitioned to new managers.
[2]	The cost of these securities was determined on the basis of specific identification.
[3]	Effective January 1, 2018, unrealized gains (losses) on equity securities are recorded in Net Income instead of Other Comprehensive Income (Loss).
[4]	Includes activity in accounts related to the liquidation of funds being transitioned to new managers.
[5]	The cost of these securities was determined on the basis of specific identification.
[6]	Effective January 1, 2018, unrealized gains (losses) on equity securities are recorded in Net Income instead of Other Comprehensive Income (Loss).

Trust Investments (Narrative) (

Trust Investments (Narrative) (Detail) $ in Millions	12 Months Ended
	Dec. 31, 2018USD ($)
Nuclear Decommissioning Trust (NDT) Fund [Member] | Power [Member]
Schedule of Trust Investments [Line Items]
Decommissioning Liability, Noncurrent	$ 708
Nuclear Decommissioning Trust (NDT) Fund [Member] | Power [Member] | Minimum [Member]
Schedule of Trust Investments [Line Items]
Decommissioning Costs Including Contingencies	2,800
Nuclear Decommissioning Trust (NDT) Fund [Member] | Power [Member] | Maximum [Member]
Schedule of Trust Investments [Line Items]
Decommissioning Costs Including Contingencies	3,000
Debt Securities [Member] | Nuclear Decommissioning Trust (NDT) Fund [Member] | Power [Member]
Schedule of Trust Investments [Line Items]
Other Comprehensive Income (Loss), Available-for-sale Securities Adjustment, Net of Tax, Portion Attributable to Parent	(12)
Debt Securities [Member] | Rabbi Trust [Member]
Schedule of Trust Investments [Line Items]
Other Comprehensive Income (Loss), Available-for-sale Securities Adjustment, Net of Tax, Portion Attributable to Parent	$ (4)

Trust Investments (Amount Of Av

Trust Investments (Amount Of Available-For-Sale Debt Securities By Maturity Periods) (Detail) $ in Millions	Dec. 31, 2018USD ($)
Nuclear Decommissioning Trust (NDT) Fund [Member]
Schedule of Trust Investments [Line Items]
Available-for-sale debt securities, Less than one year	$ 13
Available-for-sale debt securities, 1-5 years	254
Available-for-sale debt securities, 6-10 years	211
Available-for-sale debt securities, 11-15 years	40
Available-for-sale debt securities, 16-20 years	77
Available-for-sale debt securities, Over 20 years	383
Total Available-for-Sale Debt Securities	978
Rabbi Trust [Member]
Schedule of Trust Investments [Line Items]
Available-for-sale debt securities, Less than one year	1
Available-for-sale debt securities, 1-5 years	35
Available-for-sale debt securities, 6-10 years	27
Available-for-sale debt securities, 11-15 years	8
Available-for-sale debt securities, 16-20 years	21
Available-for-sale debt securities, Over 20 years	109
Total Available-for-Sale Debt Securities	201
Power [Member] | Nuclear Decommissioning Trust (NDT) Fund [Member]
Schedule of Trust Investments [Line Items]
Total Available-for-Sale Debt Securities	$ 1,878

Trust Investments (Fair Value O

Trust Investments (Fair Value Of Rabbi Trust) (Detail) - Rabbi Trust [Member] - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Schedule of Trust Investments [Line Items]
Total Rabbi Trust Investments	$ 224	$ 231
Power [Member]
Schedule of Trust Investments [Line Items]
Total Rabbi Trust Investments	56	57
PSE&G [Member]
Schedule of Trust Investments [Line Items]
Total Rabbi Trust Investments	45	46
Other [Member]
Schedule of Trust Investments [Line Items]
Total Rabbi Trust Investments	$ 123	$ 128

Goodwill And Other Intangible_2

Goodwill And Other Intangibles (Narrative) (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Goodwill [Line Items]
Goodwill	$ 16	$ 16
Intangible Assets	143	114
Power [Member]
Goodwill [Line Items]
Goodwill	16	16
Intangible Assets	$ 143	$ 114	$ 98

Goodwill And Other Intangible_3

Goodwill And Other Intangibles (Schedule of Intangibles) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Goodwill [Line Items]
Purchases of Intangible Assets	$ 146	$ 117	$ 99
Intangible Assets	143	114
Power [Member]
Goodwill [Line Items]
Retirement of Intangibles	(116)	(100)
Purchases of Intangible Assets	146	117	99
Sales and Transfers of Intangible Assets	(1)	(1)
Intangible Assets	143	114	98
Renewable Energy Credits [Member] | Power [Member]
Goodwill [Line Items]
Retirement of Intangibles	(90)	(93)
Purchases of Intangible Assets	110	90
Sales and Transfers of Intangible Assets	(1)	(1)
Intangible Assets	59	40	44
Emissions Allowances [Member] | Power [Member]
Goodwill [Line Items]
Retirement of Intangibles	(26)	(7)
Purchases of Intangible Assets	36	27
Sales and Transfers of Intangible Assets	0	0
Intangible Assets	$ 84	$ 74	$ 54

Asset Retirement Obligations _3

Asset Retirement Obligations (AROs) (Impact Of The Revisions On Asset Retirement Obligation) (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2018	Dec. 31, 2017
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
ARO Liability, Beginning Balance		$ 1,024	$ 726
Liabilities Settled		(10)	(29)
Liabilities Incurred		1	1
Accretion Expense		41	30
Accretion Expense Deferred and Recovered in Rate Base	[1]	12	12
Revision to Present Value of Future Cash Flows		(5)	284
ARO Liability, Ending Balance		1,063	1,024
PSE&G [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
ARO Liability, Beginning Balance		212	213
Liabilities Settled		(9)	(8)
Liabilities Incurred		0	0
Accretion Expense		0	0
Accretion Expense Deferred and Recovered in Rate Base	[1]	12	12
Revision to Present Value of Future Cash Flows		87	(5)
ARO Liability, Ending Balance		302	212
Power [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
ARO Liability, Beginning Balance		810	511
Liabilities Settled		(1)	(21)
Liabilities Incurred		1	1
Accretion Expense		41	30
Accretion Expense Deferred and Recovered in Rate Base	[1]	0	0
Revision to Present Value of Future Cash Flows		(93)	289
ARO Liability, Ending Balance		758	810
Increase in ARO liability due to higher probability of early retirement			276
Other [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
ARO Liability, Beginning Balance		2	2
Liabilities Settled		0	0
Liabilities Incurred		0	0
Accretion Expense		0	0
Accretion Expense Deferred and Recovered in Rate Base	[1]	0	0
Revision to Present Value of Future Cash Flows		1	0
ARO Liability, Ending Balance		$ 3	$ 2
[1]	Not reflected as expense in Consolidated Statements of Operations

Pension, OPEB and Savings Pla_3

Pension, OPEB and Savings Plans (Narrative) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018USD ($)plan	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)
Defined Benefit Plan Disclosure [Line Items]
Number of PSEG's defined contribution plans | plan		2
Defined benefit plan funded status of plan percentage		86.00%
Rabbi trust assets used to fund nonqualified pension plans		$ 224
Defined benefit plans, projected benefit and accumulated benefit obligations		5,700	$ 6,100
OPEB Plan estimated contribution in next fiscal year		$ 10
Maximum annual 401(k) contribution per employee, percent		50.00%
Defined Contribution Plan, Employer Matching Contribution, Percent of Match		50.00%
Total Employer Matching Contributions		$ 41	41	$ 41
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Accumulated Other Comprehensive (Income) Loss, Defined Benefit Plan, after Tax		360	406
Accumulated Other Comprehensive Income (Loss), Defined Benefit Pension and Other Postretirement Plans, Before Tax		619	683
Defined Benefit Plan, Net Periodic Benefit Cost (Credit)		$ (36)	$ 3	$ 56
Expected long-term rate of return on plan assets		7.80%	7.80%	8.00%
Interest in Master Trust assets percentage		91.00%
Defined Benefit Plan, Benefit Obligation, Increase (Decrease) for Plan Amendment		$ 0	$ 0
Other Pension Plan, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Benefit Obligation		156
Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit)		$ 106	$ 86	$ 71
Expected long-term rate of return on plan assets		7.80%	7.80%	8.00%
Interest in Master Trust assets percentage			9.00%
Defined Benefit Plan, Benefit Obligation, Increase (Decrease) for Plan Amendment		$ 559	$ 0
Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Target allocation percentage of assets		70.00%
Fixed Income Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Target allocation percentage of assets		30.00%
Power [Member]
Defined Benefit Plan Disclosure [Line Items]
Total Employer Matching Contributions		$ 10	11	$ 12
Power [Member] | Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit)		(9)	1	16
Power [Member] | Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit)		$ 32	27	23
Thrift Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Employer matching contribution, percent		8.00%
Savings Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Employer matching contribution, percent		7.00%
Long Island Electric Utility Servco LLC Pension and OPEB [Member]
Defined Benefit Plan Disclosure [Line Items]
Number of PSEG's defined contribution plans | plan		2
Defined Benefit Plan, Expected Future Employer Contributions, Next Fiscal Year		$ 28
Maximum annual 401(k) contribution per employee, percent		50.00%
Defined Contribution Plan, Employer Matching Contribution, Percent of Match		50.00%
Employer matching contribution, percent		8.00%
Total Employer Matching Contributions		$ 7	6	5
Long Island Electric Utility Servco LLC Pension and OPEB [Member] | Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit)		$ 40	35	28
Expected long-term rate of return on plan assets		7.60%
Defined Benefit Plan, Benefit Obligation, Increase (Decrease) for Plan Amendment		$ 0	0
Long Island Electric Utility Servco LLC Pension and OPEB [Member] | Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit)		6	4	$ 2
Defined Benefit Plan, Benefit Obligation, Increase (Decrease) for Plan Amendment		$ 0	$ 0
Long Island Electric Utility Servco LLC Pension and OPEB [Member] | Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Target allocation percentage of assets		70.00%
Long Island Electric Utility Servco LLC Pension and OPEB [Member] | Fixed Income Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Target allocation percentage of assets		30.00%
Subsequent Event [Member] | Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Expected long-term rate of return on plan assets	7.80%
Subsequent Event [Member] | Long Island Electric Utility Servco LLC Pension and OPEB [Member] | Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Expected long-term rate of return on plan assets	7.60%

Pension, OPEB and Savings Pla_4

Pension, OPEB and Savings Plans (Changes In The Benefit Obligation And The Fair Value Of Plan Assets) (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2018		Dec. 31, 2017		Dec. 31, 2016
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Assets at Beginning of Year	[1]	$ 6,310
Fair Value of Assets at End of Year	[1]	5,595		$ 6,310
Defined Benefit Plan, Amounts for Asset (Liability) Recognized in Statement of Financial Position [Abstract]
Accrued Benefit Cost		(109)		(129)
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Regulatory Assets		1,090		1,485
Deferred Costs and Other Assets		127		133
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Benefit Obligation at Beginning of Year	[2]	6,359		5,772
Service Cost		130		114		$ 109
Interest Cost		208		204		202
Actuarial (Gain) Loss		(460)		564
Gross Benefits Paid		(316)		(295)
Plan Assumptions		0		0
Benefit Obligation at End of Year	[2]	5,921		6,359		5,772
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Assets at Beginning of Year		5,812		5,193
Actual Return on Plan Assets		(388)		903
Employer Contributions		12		11
Gross Benefits Paid		(316)		(295)
Fair Value of Assets at End of Year		5,120		5,812		5,193
Funded Status (Plan Assets less Benefit Obligation)		(801)		(547)
Defined Benefit Plan, Amounts for Asset (Liability) Recognized in Statement of Financial Position [Abstract]
Current Accrued Benefit Cost		(10)		(10)
Accrued Benefit Cost		(791)		(537)
Amounts Recognized		(801)		(547)
Defined Benefit Plan, Accumulated Other Comprehensive (Income) Loss, before Tax [Abstract]
Prior Service Cost		(28)		(46)
Net Actuarial Loss		2,005		1,721
Total	[3]	(1,977)		(1,675)
Other Benefits [Member]
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Benefit Obligation at Beginning of Year	[2]	1,976		1,754
Service Cost		18		17		17
Interest Cost		66		63		59
Actuarial (Gain) Loss		(222)		199
Gross Benefits Paid		(76)		(57)
Plan Assumptions		(559)		0
Benefit Obligation at End of Year	[2]	1,203		1,976		1,754
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Assets at Beginning of Year		511		420
Actual Return on Plan Assets		(36)		77
Employer Contributions		89		71
Gross Benefits Paid		(76)		(57)
Fair Value of Assets at End of Year		488		511		420
Funded Status (Plan Assets less Benefit Obligation)		(715)		(1,465)
Defined Benefit Plan, Amounts for Asset (Liability) Recognized in Statement of Financial Position [Abstract]
Current Accrued Benefit Cost		(11)		(10)
Accrued Benefit Cost		(704)		(1,455)
Amounts Recognized		(715)		(1,465)
Defined Benefit Plan, Accumulated Other Comprehensive (Income) Loss, before Tax [Abstract]
Prior Service Cost		(561)		(3)
Net Actuarial Loss		420		629
Total	[3]	141		(626)
Long Island Electric Utility Servco LLC Pension and OPEB [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Assets at Beginning of Year		191
Fair Value of Assets at End of Year		212		191
Long Island Electric Utility Servco LLC Pension and OPEB [Member] | Pension Benefits [Member]
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Benefit Obligation at Beginning of Year		320	[4]	262
Service Cost		30		27
Interest Cost		12		11
Actuarial (Gain) Loss		(38)		22
Gross Benefits Paid		(3)		(2)
Plan Assumptions		0		0
Benefit Obligation at End of Year		321	[4]	320	[4]	262
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Assets at Beginning of Year		191		134
Actual Return on Plan Assets		(16)		24
Employer Contributions		40		35
Gross Benefits Paid		(3)		(2)
Fair Value of Assets at End of Year		212		191		134
Funded Status (Plan Assets less Benefit Obligation)		(109)		(129)
Defined Benefit Plan, Amounts for Asset (Liability) Recognized in Statement of Financial Position [Abstract]
Accrued Benefit Cost		(109)		(129)
Amounts Recognized	[5]	(109)		(129)
Long Island Electric Utility Servco LLC Pension and OPEB [Member] | Other Benefits [Member]
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Benefit Obligation at Beginning of Year		542	[4]	452
Service Cost		18		15
Interest Cost		20		19
Actuarial (Gain) Loss		(73)		60
Gross Benefits Paid		(6)		(4)
Plan Assumptions		0		0
Benefit Obligation at End of Year		501	[4]	542	[4]	452
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Assets at Beginning of Year		0		0
Actual Return on Plan Assets		0		0
Employer Contributions		6		4
Gross Benefits Paid		(6)		(4)
Fair Value of Assets at End of Year		0		0		$ 0
Funded Status (Plan Assets less Benefit Obligation)		(501)		(542)
Defined Benefit Plan, Amounts for Asset (Liability) Recognized in Statement of Financial Position [Abstract]
Accrued Benefit Cost		(501)		(542)
Amounts Recognized	[5]	$ (501)		$ (542)
[1]	Excludes net receivables of $14 million and $13 million at December 31, 2018 and 2017, respectively, which consist of interest, dividends and receivables and payables related to pending securities sales and purchases.
[2]	Represents projected benefit obligation for pension benefits and the accumulated postretirement benefit obligation for other benefits. The vested benefit obligation is the actuarial present value of the vested benefits to which the employee is currently entitled but based on the employee’s expected date of separation of retirement.
[3]	Includes $619 million ($360 million, after-tax) and $683 million ($406 million, after-tax) in Accumulated Other Comprehensive Loss related to Pension and OPEB as of December 31, 2018 and 2017, respectively. Also includes Regulatory Assets of $1,090 million and Deferred Assets of $127 million as of December 31, 2018 and Regulatory Assets of $1,485 million and Deferred Assets of $133 million as of December 31, 2017.
[4]	Represents projected benefit obligation for pension benefits and the accumulated postretirement benefit obligation for other benefits. The vested benefit obligation is the actuarial present value of the vested benefits to which the employee is currently entitled but based on the employee’s expected date of separation of retirement.
[5]	Amounts equal to the accrued pension and OPEB costs of Servco are offset in Long-Term Receivable of VIE on PSEG’s Consolidated Balance Sheets.

Pension, OPEB and Savings Pla_5

Pension, OPEB and Savings Plans (Components Of Net Periodic Benefit Cost) (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Defined Benefit Plan Disclosure [Line Items]
Non-Operating Pension and Other Postretirement Plan (Credits) Costs	$ (76)	$ 0	$ 22
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Service Cost	130	114	109
Interest Cost	208	204	202
Expected Return on Plan Assets	(441)	(394)	(394)
Amortization of Prior Service Cost	(18)	(18)	(19)
Amortization of Actuarial Loss	85	97	158
Non-Operating Pension and Other Postretirement Plan (Credits) Costs	(166)	(111)	(53)
Net Periodic Benefit Cost	(36)	3	56
Total Benefit Costs, Including Effect of Regulatory Asset	(36)	3	56
Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Service Cost	18	17	17
Interest Cost	66	63	59
Expected Return on Plan Assets	(41)	(34)	(31)
Amortization of Prior Service Cost	(1)	(11)	(14)
Amortization of Actuarial Loss	64	51	40
Non-Operating Pension and Other Postretirement Plan (Credits) Costs	88	69	54
Net Periodic Benefit Cost	106	86	71
Total Benefit Costs, Including Effect of Regulatory Asset	$ 106	$ 86	$ 71

Pension, OPEB and Savings Pla_6

Pension, OPEB and Savings Plans (Schedule Of Pension And OPEB Costs) (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit)	$ (36)	$ 3	$ 56
Total Benefit Costs	(36)	3	56
Pension Benefits [Member] | PSE&G [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit)	(31)	(4)	29
Pension Benefits [Member] | Power [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit)	(9)	1	16
Pension Benefits [Member] | Other [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit)	4	6	11
Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit)	106	86	71
Total Benefit Costs	106	86	71
Other Benefits [Member] | PSE&G [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit)	68	54	43
Other Benefits [Member] | Power [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit)	32	27	23
Other Benefits [Member] | Other [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit)	$ 6	$ 5	$ 5

Pension, OPEB and Savings Pla_7

Pension, OPEB and Savings Plans (Pre-Tax Changes Recognized In Accumulated Other Comprehensive Income (Loss), Regulatory Assets And Deferred Assets) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Net Actuarial (Gain) Loss in Current Period	$ 369	$ 55
Amortization of Net Actuarial Gain (Loss)	(85)	(97)
Prior Service Cost (Credit) in current period	0	0
Amortization of Prior Service Credit	18	18
Total	302	(24)
Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Net Actuarial (Gain) Loss in Current Period	(145)	156
Amortization of Net Actuarial Gain (Loss)	(64)	(50)
Prior Service Cost (Credit) in current period	(559)	0
Amortization of Prior Service Credit	1	11
Total	$ (767)	$ 117

Pension, OPEB and Savings Pla_8

Pension, OPEB and Savings Plans (Amounts Expected To Be Amortized From Accumulated OCL, Regulatory Assets And Deferred Assets Into Net Periodic Benefit Cost) (Details) $ in Millions	Dec. 31, 2018USD ($)
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Actuarial (Gain) Loss	$ 107
Prior Service Cost	(18)
Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Actuarial (Gain) Loss	50
Prior Service Cost	$ (128)

Pension, OPEB and Savings Pla_9

Pension, OPEB and Savings Plans (Assumptions Used To Determine The Benefit Obligations And Net Periodic Benefit Costs) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount Rate	4.41%	3.73%	4.29%
Expected Return on Plan Assets	7.80%	7.80%	8.00%
Rate of Compensation Increase	3.90%	3.90%	3.61%
Service Cost Interest Rate	3.88%	4.53%	4.81%
Interest Cost Interest Rate	3.35%	3.63%	3.75%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase	3.90%	3.61%	3.61%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate	3.73%	4.29%	4.54%
Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount Rate	4.31%	3.76%	4.37%
Expected Return on Plan Assets	7.80%	7.80%	8.00%
Rate of Compensation Increase	3.90%	3.90%	3.61%
Service Cost Interest Rate	3.90%	4.64%	4.87%
Interest Cost Interest Rate	3.39%	3.69%	3.76%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase	3.90%	3.61%	3.61%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate	3.76%	4.37%	4.58%
Immediate Rate	7.28%	7.93%	7.55%
Ultimate Rate	4.75%	4.75%	4.75%
Year Ultimate Rate Reached	2,026	2,026	2,025
Total of Service Cost and Interest Cost effect of 1 percent increase	$ 1	$ 13	$ 11
Postretirement Benefit Obligation effect of 1 percent increase	21	240	191
Total of Service Cost and Interest Cost effect of 1 percent decrease	(1)	(10)	(9)
Postretirement Benefit Obligation effect of 1 percent decrease	$ (20)	$ (198)	$ (160)
Long Island Electric Utility Servco LLC Pension and OPEB [Member] | Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount Rate	4.60%	3.90%	4.61%
Expected Return on Plan Assets	7.60%
Rate of Compensation Increase	3.25%	3.25%	3.25%
Long Island Electric Utility Servco LLC Pension and OPEB [Member] | Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount Rate	4.67%	3.96%	4.71%
Rate of Compensation Increase	3.25%	3.25%	3.25%
Immediate Rate	8.03%	7.69%	7.55%
Ultimate Rate	4.75%	4.75%	4.75%
Year Ultimate Rate Reached	2,026	2,026	2,025
Postretirement Benefit Obligation effect of 1 percent increase	$ 108	$ 131	$ 97
Postretirement Benefit Obligation effect of 1 percent decrease	$ (83)	$ (99)	$ (75)

Pension, OPEB and Savings Pl_10

Pension, OPEB and Savings Plans (Fair Value Measurements And The Levels Of Inputs Used In Determining Fair Values) (Details) - USD ($) $ in Millions		Dec. 31, 2018	Dec. 31, 2017
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	[1]	$ 5,595	$ 6,310
Interest and dividend receivables		14	13
Cash Equivalents [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	[2]	99	133
Common Stock [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	[3]	1,156	1,275
Commingled Equities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	[4]	1,338	1,401
Government-Other [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	[5]	302	272
US Treasury Obligations [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	[5]	526	571
Corporate [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	[5]	948	963
Subtotal before Measured at Net Asset Value Practical Expedient [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		4,377	4,621
Commingled Equities at NAV [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	[6]	1,208	1,675
Preferred Stock [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	[3]	7	6
Private Equity [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	[7]	10	14
Quoted Market Prices for Identical Assets (Level 1) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets
Quoted Market Prices for Identical Assets (Level 1) [Member] | Cash Equivalents [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	[2]	88	117
Quoted Market Prices for Identical Assets (Level 1) [Member] | Common Stock [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	[3]	1,156	1,275
Quoted Market Prices for Identical Assets (Level 1) [Member] | Commingled Equities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	[4]	960	1,218
Quoted Market Prices for Identical Assets (Level 1) [Member] | Government-Other [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	[5]	0	0
Quoted Market Prices for Identical Assets (Level 1) [Member] | US Treasury Obligations [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	[5]	0	0
Quoted Market Prices for Identical Assets (Level 1) [Member] | Corporate [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	[5]	0	0
Quoted Market Prices for Identical Assets (Level 1) [Member] | Subtotal before Measured at Net Asset Value Practical Expedient [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		2,212	2,616
Quoted Market Prices for Identical Assets (Level 1) [Member] | Preferred Stock [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	[3]	7	6
Significant Other Observable Inputs (Level 2) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets
Significant Other Observable Inputs (Level 2) [Member] | Cash Equivalents [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	[2]	11	16
Significant Other Observable Inputs (Level 2) [Member] | Common Stock [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	[3]	0	0
Significant Other Observable Inputs (Level 2) [Member] | Commingled Equities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	[4]	378	183
Significant Other Observable Inputs (Level 2) [Member] | Government-Other [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	[5]	302	272
Significant Other Observable Inputs (Level 2) [Member] | US Treasury Obligations [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	[5]	526	571
Significant Other Observable Inputs (Level 2) [Member] | Corporate [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	[5]	948	963
Significant Other Observable Inputs (Level 2) [Member] | Subtotal before Measured at Net Asset Value Practical Expedient [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		2,165	2,005
Significant Other Observable Inputs (Level 2) [Member] | Preferred Stock [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	[3]	0	0
Pension And OPEB Plans Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets
Pension And OPEB Plans Level 3 [Member] | Cash Equivalents [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	[2]	0	0
Pension And OPEB Plans Level 3 [Member] | Common Stock [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	[3]	0	0
Pension And OPEB Plans Level 3 [Member] | Commingled Equities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	[4]	0	0
Pension And OPEB Plans Level 3 [Member] | Government-Other [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	[5]	0	0
Pension And OPEB Plans Level 3 [Member] | US Treasury Obligations [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	[5]	0	0
Pension And OPEB Plans Level 3 [Member] | Corporate [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	[5]	0	0
Pension And OPEB Plans Level 3 [Member] | Subtotal before Measured at Net Asset Value Practical Expedient [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		0	0
Pension And OPEB Plans Level 3 [Member] | Preferred Stock [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	[3]	0	0
Long Island Electric Utility Servco LLC Pension and OPEB [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		212	191
Long Island Electric Utility Servco LLC Pension and OPEB [Member] | Commingled Equities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	[8]	141	137
Long Island Electric Utility Servco LLC Pension and OPEB [Member] | Fixed Income Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	[8]	71	54
Long Island Electric Utility Servco LLC Pension and OPEB [Member] | Quoted Market Prices for Identical Assets (Level 1) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		0	0
Long Island Electric Utility Servco LLC Pension and OPEB [Member] | Quoted Market Prices for Identical Assets (Level 1) [Member] | Commingled Equities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	[8]	0	0
Long Island Electric Utility Servco LLC Pension and OPEB [Member] | Quoted Market Prices for Identical Assets (Level 1) [Member] | Fixed Income Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	[8]	0	0
Long Island Electric Utility Servco LLC Pension and OPEB [Member] | Significant Other Observable Inputs (Level 2) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		212	191
Long Island Electric Utility Servco LLC Pension and OPEB [Member] | Significant Other Observable Inputs (Level 2) [Member] | Commingled Equities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	[8]	141	137
Long Island Electric Utility Servco LLC Pension and OPEB [Member] | Significant Other Observable Inputs (Level 2) [Member] | Fixed Income Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	[8]	71	54
Long Island Electric Utility Servco LLC Pension and OPEB [Member] | Pension And OPEB Plans Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		0	0
Long Island Electric Utility Servco LLC Pension and OPEB [Member] | Pension And OPEB Plans Level 3 [Member] | Commingled Equities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	[8]	0	0
Long Island Electric Utility Servco LLC Pension and OPEB [Member] | Pension And OPEB Plans Level 3 [Member] | Fixed Income Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	[8]	$ 0	$ 0
[1]	Excludes net receivables of $14 million and $13 million at December 31, 2018 and 2017, respectively, which consist of interest, dividends and receivables and payables related to pending securities sales and purchases.
[2]	The Collective Investment Fund publishes a daily net asset value (NAV) which participants may use for daily redemptions without restrictions (Level 1). Certain temporary investments are valued using inputs such as time-to-maturity, coupon rate, quality rating and current yield (Level 2).
[3]	Common stocks and preferred stocks are measured using observable data in active markets and considered Level 1.
[4]	Commingled Funds that allow daily redemption at their daily published NAV without restrictions are classified as Level 1. Commingled Funds that publish daily NAV but with certain near-term redemption restrictions which prevent redemption at the published daily NAV are classified as Level 2.
[5]	Debt securities include mainly investment grade corporate and municipal bonds, U.S. Treasury obligations and Federal Agency asset-backed securities with a wide range of maturities. These investments are valued using an evaluated pricing approach that varies by asset class and reflects observable market information such as the most recent exchange price or quoted bid for similar securities. Market-based standard inputs typically include benchmark yields, reported trades, broker/dealer quotes and issuer spreads or the most recent quotes for similar securities which are a Level 2 measure.
[6]	Certain commingled equity funds are not included in the fair value hierarchy as they are measured at fair value using the NAV per share (or its equivalent) practical expedient. These funds do not meet the definition of readily determinable fair value due to limitations in published NAV (last business day of the month) and include certain redemption restrictions ranging from one to fifteen days advance notice prior to redemption days and limitations on withdrawals over 25% of the total fund. The objectives of these funds are mainly tracking the S&P Index or achieving long-term growth through investment in foreign equity securities and the MSCI Emerging Markets Index.
[7]	Private equity investments primarily include various limited partnerships that invest in either operating companies through acquisitions or developing a portfolio of non-US distressed investments to maximize total return on capital. These investments are valued at NAV (or its equivalent) on an annual basis and have significant redemption restrictions preventing redemption until fund liquidation and limited ability to sell these investments. Fund liquidation is not expected to occur for several more years. These investments have been removed from the fair value hierarchy in accordance with the guidance on NAV practical expedient.
[8]	Investments in commingled equity and bond funds have a readily determinable fair value as they publish a daily NAV available to investors which is the basis for current transactions and contain certain redemption restrictions requiring advance notice of one to two days for withdrawals (Level 2).

Pension, OPEB and Savings Pl_11

Pension, OPEB and Savings Plans (Reconciliations Of The Beginning And Ending Balances Of Pension And OPEB Plans' Level 3 Assets) (Details) $ in Millions	Dec. 31, 2018USD ($)
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Assets at Beginning of Year	$ 6,310	[1]
Fair Value of Assets at End of Year	5,595	[1]
Pension And OPEB Plans Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Assets at Beginning of Year
Fair Value of Assets at End of Year
Private Equity [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Assets at Beginning of Year	14	[2]
Fair Value of Assets at End of Year	$ 10	[2]
[1]	Excludes net receivables of $14 million and $13 million at December 31, 2018 and 2017, respectively, which consist of interest, dividends and receivables and payables related to pending securities sales and purchases.
[2]	Private equity investments primarily include various limited partnerships that invest in either operating companies through acquisitions or developing a portfolio of non-US distressed investments to maximize total return on capital. These investments are valued at NAV (or its equivalent) on an annual basis and have significant redemption restrictions preventing redemption until fund liquidation and limited ability to sell these investments. Fund liquidation is not expected to occur for several more years. These investments have been removed from the fair value hierarchy in accordance with the guidance on NAV practical expedient.

Pension, OPEB and Savings Pl_12

Pension, OPEB and Savings Plans (Schedule Of Percentage Of Fair Value Of Total Plan Assets) (Details)	Dec. 31, 2018	Dec. 31, 2017
Defined Benefit Plan Disclosure [Line Items]
Actual plan asset allocation, percent	100.00%	100.00%
Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Actual plan asset allocation, percent	66.00%	69.00%
Fixed Income Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Actual plan asset allocation, percent	32.00%	29.00%
Other Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Actual plan asset allocation, percent	2.00%	2.00%
Long Island Electric Utility Servco LLC Pension and OPEB [Member]
Defined Benefit Plan Disclosure [Line Items]
Actual plan asset allocation, percent	100.00%	100.00%
Long Island Electric Utility Servco LLC Pension and OPEB [Member] | Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Actual plan asset allocation, percent	67.00%	72.00%
Long Island Electric Utility Servco LLC Pension and OPEB [Member] | Fixed Income Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Actual plan asset allocation, percent	33.00%	28.00%

Pension, OPEB and Savings Pl_13

Pension, OPEB and Savings Plans (Estimated Future Benefit Payments) (Details) $ in Millions	Dec. 31, 2018USD ($)
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Payments Expected Next Twelve Months	$ 345
Payments Expected Year Two	341
Payments Expected Year Three	352
Payments Expected Year Four	364
Payments Expected Year Five	373
Payments Expected Thereafter	2,004
Total Estimated Future Benefit Payments	3,779
Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Payments Expected Next Twelve Months	91
Payments Expected Year Two	95
Payments Expected Year Three	87
Payments Expected Year Four	88
Payments Expected Year Five	89
Payments Expected Thereafter	428
Total Estimated Future Benefit Payments	878
Long Island Electric Utility Servco LLC Pension and OPEB [Member] | Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Payments Expected Next Twelve Months	4
Payments Expected Year Two	6
Payments Expected Year Three	7
Payments Expected Year Four	9
Payments Expected Year Five	11
Payments Expected Thereafter	91
Total Estimated Future Benefit Payments	128
Long Island Electric Utility Servco LLC Pension and OPEB [Member] | Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Payments Expected Next Twelve Months	6
Payments Expected Year Two	8
Payments Expected Year Three	10
Payments Expected Year Four	12
Payments Expected Year Five	14
Payments Expected Thereafter	99
Total Estimated Future Benefit Payments	$ 149

Pension, OPEB and Savings Pl_14

Pension, OPEB and Savings Plans (Schedule Of Amount Paid For Employer Matching Contributions) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Total Employer Matching Contributions	$ 41	$ 41	$ 41
Power [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Total Employer Matching Contributions	10	11	12
PSE&G [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Total Employer Matching Contributions	26	25	24
Other [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Total Employer Matching Contributions	$ 5	$ 5	$ 5

Commitments And Contingent Li_3

Commitments And Contingent Liabilities (Face Value Of Outstanding Guarantees, Current Exposure And Margin Positions) (Detail) - Power [Member] - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Other Commitments [Line Items]
Face Value of Outstanding Guarantees	$ 1,772	$ 1,701
Exposure under Current Guarantees	198	153
Letters of Credit Margin Posted	115	103
Letters of Credit Margin Received	26	32
Counterparty Cash Margin Deposited	0	0
Counterparty Cash Margin Received	(10)	(1)
Net Broker Balance Deposited (Received)	403	147
Other Letters of Credit	$ 52	$ 61

Commitments And Contingent Li_4

Commitments And Contingent Liabilities (Environmental Matters) (Detail) $ in Millions	12 Months Ended
	Dec. 31, 2018USD ($)Potentially_Responsible_PartysiteentityStationPlantmi	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)
Site Contingency [Line Items]
Percentage of residential gas supply permitted to be recovered in gas hedging by BPU	80.00%
Number of miles related to the Passaic River constituting a facility as determined by the US Environmental Protection Agency | mi	17
Number of legal entities contacted by EPA in conjunction with Newark Bay study area contamination | entity	11
Number of operating electric generating stations located on Hackensack River | Station	2
Number of former MGP contamination sites located on Hackensack river in conjunction with Newark Bay study area contamination | site	1
Accrued environmental costs	$ 327	$ 357
Operation and Maintenance	3,015	2,901	$ 2,991
New England Generation Fleet	12,744	12,250
Clean Energy Program Current	$ 143	128
PSE&G [Member]
Site Contingency [Line Items]
Percentage Of Cost Attributable To Potentially Responsible Party	7.60%
Accrued environmental costs	$ 268	283
Regulatory Assets	3,788	3,433
Operation and Maintenance	1,575	1,458	1,465
New England Generation Fleet	623	593
Clean Energy Program Current	143	128
Power [Member]
Site Contingency [Line Items]
Operation and Maintenance	999	1,046	$ 1,139
New England Generation Fleet	12,121	$ 11,657
MGP Remediation Site Contingency [Member] | PSE&G [Member]
Site Contingency [Line Items]
Remediation liability recorded as other current liabilities	56
Remediation liability recorded as environmental costs in noncurrent liabilities	265
Regulatory Assets	$ 321
PSE&G's Former MGP Sites [Member]
Site Contingency [Line Items]
Number of MGP sites identified by registrant and the NJDEP requiring some level of remedial action | site	38
PSE&G's Former MGP Sites [Member] | Power [Member]
Site Contingency [Line Items]
Percentage Of Cost Attributable To Potentially Responsible Party	1.90%
Passaic River Site Contingency [Member]
Site Contingency [Line Items]
Estimated Cleanup Costs EPA Preferred Method	$ 2,300
Aggregate number of PRPs directed by the NJDEP to arrange for natural resource damage assessment and interim compensatory restoration along the lower Passaic River | Potentially_Responsible_Party	56
Estimated cost of interim natural resource injury restoration	$ 950
Accrual for Environmental Loss Contingencies	$ 57
Passaic River Site Contingency [Member] | Transferred To Power From PSE&G [Member]
Site Contingency [Line Items]
Number of operating electric generating station (Essex Site) | Plant	1
Passaic River Site Contingency [Member] | PSE&G [Member]
Site Contingency [Line Items]
Number of former generating electric station | Plant	1
Number of former Manufactured Gas Plant (MGP) sites | Plant	4
Accrual for Environmental Loss Contingencies	$ 46
Passaic River Site Contingency [Member] | Power [Member]
Site Contingency [Line Items]
Accrual for Environmental Loss Contingencies	11
Minimum [Member] | MGP Remediation Site Contingency [Member] | PSE&G [Member]
Site Contingency [Line Items]
Loss Contingency, Estimate of Possible Loss	321
Accrual for Environmental Loss Contingencies	321
Minimum [Member] | Passaic River Site Contingency [Member]
Site Contingency [Line Items]
Loss Contingency, Estimate of Possible Loss	518
Maximum [Member] | MGP Remediation Site Contingency [Member] | PSE&G [Member]
Site Contingency [Line Items]
Loss Contingency, Estimate of Possible Loss	366
Maximum [Member] | Passaic River Site Contingency [Member]
Site Contingency [Line Items]
Loss Contingency, Estimate of Possible Loss	3,200
Claim against Tierra and Maxus amount	$ 14,000

Commitments And Contingent Li_5

Commitments And Contingent Liabilities (Basic Generation Service (BGS) And Basic Gas Supply Service (BGSS)) (Detail) cf in Billions	12 Months Ended
	Dec. 31, 2018cf$ / mwd$ / mwhMW
Long-term Purchase Commitment [Line Items]
Number of cubic feet in gas hedging permitted to be recovered by BPU | cf	115
Percentage of residential gas supply permitted to be recovered in gas hedging by BPU	80.00%
Percentage of annual residential gas supply requirements to be hedged	50.00%
Number of cubic feet to be hedged | cf	70
PSE&G [Member] | Auction Year 2016 [Member]
Long-term Purchase Commitment [Line Items]
36-Month Terms Ending	May 31, 2019
Load (MW) | MW	2,800
Dollars Per Megawatt Hour | $ / mwh	96.38
PSE&G [Member] | Auction Year 2017 [Member]
Long-term Purchase Commitment [Line Items]
36-Month Terms Ending	May 31, 2020
Load (MW) | MW	2,800
Dollars Per Megawatt Hour | $ / mwh	90.78
PSE&G [Member] | Auction Year 2018 [Member]
Long-term Purchase Commitment [Line Items]
36-Month Terms Ending	May 31, 2021
Load (MW) | MW	2,900
$ per kWh | $ / mwd	287.76
Dollars Per Megawatt Hour | $ / mwh	91.77
PSE&G [Member] | Auction Year 2019 [Member]
Long-term Purchase Commitment [Line Items]
36-Month Terms Ending	May 31, 2022	[1]
Load (MW) | MW	2,800
$ per kWh | $ / mwd	281.78
Dollars Per Megawatt Hour | $ / mwh	98.04
[1]	Prices set in the 2019 BGS auction will become effective on June 1, 2019 when the 2016 BGS auction agreements expire.

Commitments And Contingent Li_6

Commitments And Contingent Liabilities (Minimum Fuel Purchase Requirements) (Detail) - Power [Member] $ in Millions	12 Months Ended
	Dec. 31, 2018USD ($)
Long-term Purchase Commitment [Line Items]
Coverage percentage of nuclear fuel commitments of uranium, enrichment, and fabrication requirements	100.00%
Nuclear Fuel [Member]
Long-term Purchase Commitment [Line Items]
Total minimum purchase requirements	$ 222
Nuclear Fuel Enrichment [Member]
Long-term Purchase Commitment [Line Items]
Total minimum purchase requirements	358
Nuclear Fuel Fabrication [Member]
Long-term Purchase Commitment [Line Items]
Total minimum purchase requirements	167
Natural Gas [Member]
Long-term Purchase Commitment [Line Items]
Total minimum purchase requirements	1,102
Coal [Member]
Long-term Purchase Commitment [Line Items]
Total minimum purchase requirements	$ 429

Commitments And Contingent Li_7

Commitments And Contingent Liabilities (Regulatory Proceedings) (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Loss Contingencies [Line Items]
Costs recognized in Operation and Maintenance Expense	$ 3,015	$ 2,901	$ 2,991
PSE&G [Member]
Loss Contingencies [Line Items]
Costs recognized in Operation and Maintenance Expense	1,575	1,458	1,465
Power [Member]
Loss Contingencies [Line Items]
Costs recognized in Operation and Maintenance Expense	999	$ 1,046	$ 1,139
Maximum [Member] | Sewaren 7 Claim [Member]
Loss Contingencies [Line Items]
Loss Contingency, Estimate of Possible Loss	$ 93

Commitments And Contingent Li_8

Commitments And Contingent Liabilities (Nuclear Insurance Coverages and Assessments) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2018USD ($)
Other Commitments [Line Items]
Maximum Aggregate Assessment Per Incident	$ 433
Maximum Aggregate Annual Assessment	65
Nuclear Insurance Aggregate Limit	3,200
Total Site Coverage for Nuclear Event [Member]
Other Commitments [Line Items]
Nuclear Liability Total	13,600
Total Site Coverage for Nuclear Event [Member] | American Nuclear Insurers [Member]
Other Commitments [Line Items]
Public And Nuclear Worker Liability Primary Layer	450
Retrospective Assessments [Member]
Other Commitments [Line Items]
Replacement Power Total	$ 62

Commitments And Contingent Li_9

Commitments And Contingent Liabilities (Future Minimum Lease Payments) (Details) $ in Millions	Dec. 31, 2018USD ($)
Other Commitments [Line Items]
Operating Leases, Future Minimum Payments due, Next Twelve Months	$ 41
Operating Leases, Future Minimum Payments, Due in Two Years	40
Operating Leases, Future Minimum Payments, Due in Three Years	39
Operating Leases, Future Minimum Payments, Due in Four Years	38
Operating Leases, Future Minimum Payments, Due in Five Years	31
Operating Leases, Future Minimum Payments, Due Thereafter	222
Operating Leases, Future Minimum Payments Due	411
PSE&G [Member]
Other Commitments [Line Items]
Operating Leases, Future Minimum Payments due, Next Twelve Months	15
Operating Leases, Future Minimum Payments, Due in Two Years	11
Operating Leases, Future Minimum Payments, Due in Three Years	10
Operating Leases, Future Minimum Payments, Due in Four Years	8
Operating Leases, Future Minimum Payments, Due in Five Years	8
Operating Leases, Future Minimum Payments, Due Thereafter	66
Operating Leases, Future Minimum Payments Due	118
Power [Member]
Other Commitments [Line Items]
Operating Leases, Future Minimum Payments due, Next Twelve Months	11
Operating Leases, Future Minimum Payments, Due in Two Years	13
Operating Leases, Future Minimum Payments, Due in Three Years	13
Operating Leases, Future Minimum Payments, Due in Four Years	14
Operating Leases, Future Minimum Payments, Due in Five Years	8
Operating Leases, Future Minimum Payments, Due Thereafter	51
Operating Leases, Future Minimum Payments Due	110
Services [Member]
Other Commitments [Line Items]
Operating Leases, Future Minimum Payments due, Next Twelve Months	14
Operating Leases, Future Minimum Payments, Due in Two Years	14
Operating Leases, Future Minimum Payments, Due in Three Years	15
Operating Leases, Future Minimum Payments, Due in Four Years	15
Operating Leases, Future Minimum Payments, Due in Five Years	15
Operating Leases, Future Minimum Payments, Due Thereafter	105
Operating Leases, Future Minimum Payments Due	178
Other [Member]
Other Commitments [Line Items]
Operating Leases, Future Minimum Payments due, Next Twelve Months	1
Operating Leases, Future Minimum Payments, Due in Two Years	2
Operating Leases, Future Minimum Payments, Due in Three Years	1
Operating Leases, Future Minimum Payments, Due in Four Years	1
Operating Leases, Future Minimum Payments, Due in Five Years	0
Operating Leases, Future Minimum Payments, Due Thereafter	0
Operating Leases, Future Minimum Payments Due	$ 5

Debt and Credit Facilties (Long

Debt and Credit Facilties (Long-Term Debt) (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2018	Dec. 31, 2017
Debt Instrument [Line Items]
Long-term Debt		$ 14,558
Long-term Debt, Current Maturities		(1,294)	$ (1,000)
Total Long-Term Debt		13,168	12,068
PSEG [Member]
Debt Instrument [Line Items]
Long-term Debt		2,450	2,100
Long-term Debt, Current Maturities		(750)	0
Net Unamortized Discount and Debt Issuance Costs		(7)	(9)
Total Long-Term Debt		1,693	2,091
PSEG [Member] | Term Loan maturing in 2019 [Member]
Debt Instrument [Line Items]
Long-term Debt		$ 350	700
Maturity Year		2,019
PSEG [Member] | Term Loan maturing in 2020 [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount		$ 700	0
Maturity Year		2,020
PSEG [Member] | Variable Rate Term Loan due 2017 [Member]
Debt Instrument [Line Items]
Long-term Debt		$ 1,050	700
PSEG [Member] | Senior Notes One Point Six Zero Percent Due In Two Thousand Nineteen [Member]
Debt Instrument [Line Items]
Long-term Debt		$ 400	400
Stated interest rate of debt instrument		1.60%
Maturity Year		2,019
PSEG [Member] | Senior Notes Two Point Zero Percent Due In Two Thousand Twenty One [Member] [Member]
Debt Instrument [Line Items]
Long-term Debt		$ 300	300
Stated interest rate of debt instrument		2.00%
Maturity Year		2,021
PSEG [Member] | Senior Notes Two Point Six Five Percent Due In Two Thousand Twenty Two [Member]
Debt Instrument [Line Items]
Long-term Debt		$ 700	700
Stated interest rate of debt instrument		2.65%
Maturity Year		2,022
PSEG [Member] | Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt		$ 1,400	1,400
Power [Member]
Debt Instrument [Line Items]
Long-term Debt		2,850	2,400
Long-term Debt, Current Maturities		(44)	(250)
Net Unamortized Discount and Debt Issuance Costs		(15)	(14)
Total Long-Term Debt		2,791	2,136
Power [Member] | Senior Notes Two Point Four Five Percentage Due Two Thousand Eighteen [Member]
Debt Instrument [Line Items]
Long-term Debt		$ 0	250
Stated interest rate of debt instrument		2.45%
Maturity Year		2,018
Power [Member] | Senior Notes Five Point One Three Percentage Due Two Thousand Twenty [Member]
Debt Instrument [Line Items]
Long-term Debt		$ 406	406
Stated interest rate of debt instrument		5.13%
Maturity Year		2,020
Power [Member] | Senior Notes Four Point One Five Percentage Due Two Thousand Twenty One [Member]
Debt Instrument [Line Items]
Long-term Debt		$ 700	700
Stated interest rate of debt instrument		3.00%
Maturity Year		2,021
Power [Member] | Senior Notes Three Point Zero Percent Due In Two Thousand Twenty One [Member]
Debt Instrument [Line Items]
Long-term Debt		$ 250	250
Stated interest rate of debt instrument		4.15%
Maturity Year		2,021
Power [Member] | Senior Notes Three Point Eight Five Percent due Two Thousand Twenty Three [Member]
Debt Instrument [Line Items]
Long-term Debt		$ 700	0
Stated interest rate of debt instrument		3.85%
Debt Instrument, Face Amount		$ 700
Maturity Year		2,023
Power [Member] | Senior Notes Four Point Three Percent Due Two Thousand Twenty Three [Member]
Debt Instrument [Line Items]
Long-term Debt		$ 250	250
Stated interest rate of debt instrument		4.30%
Maturity Year		2,023
Power [Member] | Senior Notes Eight Point Six Three Percent Due Two Thousand Thirty One [Member]
Debt Instrument [Line Items]
Long-term Debt		$ 500	500
Stated interest rate of debt instrument		8.63%
Maturity Year		2,031
Power [Member] | Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt		$ 2,806	2,356
Power [Member] | Pollution Control Notes Floating Rate Due On Two Thousand Nineteen [Member]
Debt Instrument [Line Items]
Long-term Debt	[1]	$ 44	44
Maturity Year	[1]	2,019
Power [Member] | Pollution Control Notes [Member]
Debt Instrument [Line Items]
Long-term Debt		$ 44	44
PSE&G [Member]
Debt Instrument [Line Items]
Long-term Debt, Current Maturities		(500)	(750)
Total Long-Term Debt		8,684	7,841
PSE&G [Member] | First And Refunding Mortgage Bonds Nine Point Two Five Percentage Due On Two Twenty One [Member]
Debt Instrument [Line Items]
Long-term Debt	[2]	$ 134	134
Stated interest rate of debt instrument		9.25%
Maturity Year	[2]	2,021
PSE&G [Member] | First And Refunding Mortgage Bonds Eight Point Zero Zero Percentage Due On Two Thirty Seven [Member]
Debt Instrument [Line Items]
Long-term Debt	[2]	$ 7	7
Stated interest rate of debt instrument		8.00%
Maturity Year	[2]	2,037
PSE&G [Member] | First And Refunding Mortgage Bonds Five Point Zero Zero Percentage Due On Two Thirty Seven [Member]
Debt Instrument [Line Items]
Long-term Debt	[2]	$ 8	8
Stated interest rate of debt instrument		5.00%
Maturity Year	[2]	2,037
PSE&G [Member] | First And Refunding Mortgage Bonds [Member]
Debt Instrument [Line Items]
Long-term Debt		$ 149	149
PSE&G [Member] | Medium Term Notes Five Point Three Zero Percentage Due On Two Thousand Eighteen [Member]
Debt Instrument [Line Items]
Long-term Debt	[2]	$ 0	400
Stated interest rate of debt instrument		5.30%
Maturity Year	[2]	2,018
PSE&G [Member] | Medium Term Notes Two Point Three Zero Percent Due In Two Thousand Eighteen [Member]
Debt Instrument [Line Items]
Long-term Debt	[2]	$ 0	350
Stated interest rate of debt instrument		2.30%
Maturity Year	[2]	2,018
PSE&G [Member] | Medium Term Notes One Point Eight Percent Due In Two Thousand Nineteen [Member] [Domain]
Debt Instrument [Line Items]
Long-term Debt	[2]	$ 250	250
Stated interest rate of debt instrument		1.80%
Maturity Year	[2]	2,019
PSE&G [Member] | Medium Term Notes Two Point Zero Percent Due In Two Thousand Nineteen [Member]
Debt Instrument [Line Items]
Long-term Debt	[2]	$ 250	250
Stated interest rate of debt instrument		2.00%
Maturity Year	[2]	2,019
PSE&G [Member] | Medium Term Notes Three Point Five Zero Percentage Due On Two Thousand Twenty [Member]
Debt Instrument [Line Items]
Long-term Debt	[2]	$ 250	250
Stated interest rate of debt instrument		3.50%
Maturity Year	[2]	2,020
PSE&G [Member] | Medium Term Notes Seven Point Zero Four Percentage Due On Two Thousand Twenty [Member]
Debt Instrument [Line Items]
Long-term Debt	[2]	$ 9	9
Stated interest rate of debt instrument		7.04%
Maturity Year	[2]	2,020
PSE&G [Member] | Medium Term Notes One Point Nine Zero Percent Due In Two Thousand Twenty One [Member]
Debt Instrument [Line Items]
Long-term Debt	[2]	$ 300	300
Stated interest rate of debt instrument		1.90%
Maturity Year	[2]	2,021
PSE&G [Member] | Medium Term Notes Two Point Three Eight Percent Due In Two Thousand Twenty Three [Member]
Debt Instrument [Line Items]
Long-term Debt	[2]	$ 500	500
Stated interest rate of debt instrument		2.375%
Maturity Year	[2]	2,023
PSE&G [Member] | Medium Term Notes Three Point Two Five Percent due Two Thousand Twenty Three [Member]
Debt Instrument [Line Items]
Stated interest rate of debt instrument		3.25%
Debt Instrument, Face Amount	[2]	$ 325	0
Maturity Year	[2]	2,023
PSE&G [Member] | Medium Term Notes Three Point Seven Five Percent Due In Two Thousand Twenty Four [Member]
Debt Instrument [Line Items]
Long-term Debt	[2]	$ 250	250
Stated interest rate of debt instrument		3.75%
Maturity Year	[2]	2,024
PSE&G [Member] | Medium Term Notes Three Point One Five Percent Due In Two Thousand Twenty Four [Member]
Debt Instrument [Line Items]
Long-term Debt	[2]	$ 250	250
Stated interest rate of debt instrument		3.15%
Maturity Year	[2]	2,024
PSE&G [Member] | Medium Term Notes Three Point Zero Five Percent Due In Two Thousand Twenty Four [Member]
Debt Instrument [Line Items]
Long-term Debt	[2]	$ 250	250
Stated interest rate of debt instrument		3.05%
Maturity Year	[2]	2,024
PSE&G [Member] | Medium Term Notes Three Point Zero Percent Due In Two Thousand Twenty Five [Member]
Debt Instrument [Line Items]
Long-term Debt	[2]	$ 350	350
Stated interest rate of debt instrument		3.00%
Maturity Year	[2]	2,025
PSE&G [Member] | Medium Term Notes Two Point Two Five Percent due Two Thousand Twenty Six [Member]
Debt Instrument [Line Items]
Long-term Debt	[2]	$ 425	425
Stated interest rate of debt instrument		2.25%
Maturity Year	[2]	2,026
PSE&G [Member] | Medium Term Notes Three Point Zero Percent due Two Thousand Twenty Seven [Member]
Debt Instrument [Line Items]
Long-term Debt	[2]	$ 425	425
Stated interest rate of debt instrument		3.00%
Maturity Year	[2]	2,027
PSE&G [Member] | Medium Term Notes Three Point Seven Zero Percent due Two Thousand Twenty Eight [Member]
Debt Instrument [Line Items]
Long-term Debt	[2]	$ 375	0
Stated interest rate of debt instrument		3.70%
Debt Instrument, Face Amount		$ 375
Maturity Year	[2]	2,028
PSE&G [Member] | Medium Term Notes Three Point Six Five Percent due Two Thousand Twenty Eight [Member]
Debt Instrument [Line Items]
Long-term Debt	[2]	$ 325	0
Stated interest rate of debt instrument		3.65%
Debt Instrument, Face Amount		$ 325
Maturity Year	[2]	2,028
PSE&G [Member] | Medium Term Notes Five Point Two Five Percentage Due On Two Thousand Thirty Five [Member]
Debt Instrument [Line Items]
Long-term Debt	[2]	$ 250	250
Stated interest rate of debt instrument		5.25%
Maturity Year	[2]	2,035
PSE&G [Member] | Medium Term Notes Five Point Seven Zero Percentage Due On Two Thousand Thirty Six [Member]
Debt Instrument [Line Items]
Long-term Debt	[2]	$ 250	250
Stated interest rate of debt instrument		5.70%
Maturity Year	[2]	2,036
PSE&G [Member] | Medium Term Notes Five Point Eight Zero Percentage Due On Two Thousand Thirty Seven [Member]
Debt Instrument [Line Items]
Long-term Debt	[2]	$ 350	350
Stated interest rate of debt instrument		5.80%
Maturity Year	[2]	2,037
PSE&G [Member] | Medium Term Notes Five Point Three Eight Percentage Due On Two Thousand Thirty Nine [Member]
Debt Instrument [Line Items]
Long-term Debt	[2]	$ 250	250
Stated interest rate of debt instrument		5.38%
Maturity Year	[2]	2,039
PSE&G [Member] | Medium Term Notes Five Point Five Zero Percentage Due On Two Thousand Forty [Member]
Debt Instrument [Line Items]
Long-term Debt	[2]	$ 300	300
Stated interest rate of debt instrument		5.50%
Maturity Year	[2]	2,040
PSE&G [Member] | Medium-Term Notes 3.95% Due On 2042 [Member]
Debt Instrument [Line Items]
Long-term Debt	[2]	$ 450	450
Stated interest rate of debt instrument		3.95%
Maturity Year	[2]	2,042
PSE&G [Member] | Medium-Term Notes 3.65% Due On 2042 [Member]
Debt Instrument [Line Items]
Long-term Debt	[2]	$ 350	350
Stated interest rate of debt instrument		3.65%
Maturity Year	[2]	2,042
PSE&G [Member] | Medium Term Notes Three Point Eight Zero Percent Due In Two Thousand Forty Three [Member]
Debt Instrument [Line Items]
Long-term Debt	[2]	$ 400	400
Stated interest rate of debt instrument		3.80%
Maturity Year	[2]	2,043
PSE&G [Member] | Medium Term Notes Four Point Zero Percent Due In Two Thousand Forty Four [Member]
Debt Instrument [Line Items]
Long-term Debt	[2]	$ 250	250
Stated interest rate of debt instrument		4.00%
Maturity Year	[2]	2,044
PSE&G [Member] | Medium Term Notes Four Point Zero Five Percent due Two Thousand Forty Five [Member]
Debt Instrument [Line Items]
Long-term Debt	[2]	$ 250
Stated interest rate of debt instrument		4.05%
Maturity Year	[2]	2,045
PSE&G [Member] | Medium Term Notes Four Point One Five Percent Due In Two Thousand Forty Five [Member]
Debt Instrument [Line Items]
Long-term Debt	[2]	$ 250	250
Stated interest rate of debt instrument		4.15%
Maturity Year	[2]	2,045
PSE&G [Member] | Medium Term Notes Three Point Eight Zero Percent due Two Thousand Forty Six [Member]
Debt Instrument [Line Items]
Long-term Debt	[2]	$ 550	550
Stated interest rate of debt instrument		3.80%
Maturity Year	[2]	2,046
PSE&G [Member] | Medium Term Notes Three Point Six Zero Percent due Two Thousand Forty Seven [Member]
Debt Instrument [Line Items]
Long-term Debt	[2]	$ 350	350
Stated interest rate of debt instrument		3.60%
Maturity Year	[2]	2,047
PSE&G [Member] | Medium Term Notes Four Point Zero Five Percent due Two Thousand Forty Eight [Member]
Debt Instrument [Line Items]
Long-term Debt	[2]	$ 325	0
Stated interest rate of debt instrument		4.05%
Debt Instrument, Face Amount		$ 325
Maturity Year	[2]	2,048
PSE&G [Member] | Total Medium Term Notes [Member]
Debt Instrument [Line Items]
Long-term Debt		$ 9,109	8,509
PSE&G
Debt Instrument [Line Items]
Long-term Debt		9,258	8,658
Long-term Debt, Current Maturities		(500)	(750)
Net Unamortized Discount and Debt Issuance Costs		(74)	(67)
Total Long-Term Debt		$ 8,684	$ 7,841
[1]	The Pennsylvania Economic Development Authority (PEDFA) bond that is serviced and secured by Power Pollution Control Notes is a variable rate bond that is in weekly reset mode.
[2]	Secured by essentially all property of PSE&G pursuant to its First and Refunding Mortgage.

Debt and Credit Facilities (Lon

Debt and Credit Facilities (Long-Term Debt Maturities) (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Debt Instrument [Line Items]
Repayments in Next Twelve Months	$ 1,294
Repayments in Year Two	1,365
Repayments in Year Three	1,684
Repayments in Year Four	700
Repayments in Year Five	1,775
Thereafter	7,740
Long-term Debt	14,558
PSE&G
Debt Instrument [Line Items]
Repayments in Next Twelve Months	500
Repayments in Year Two	259
Repayments in Year Three	434
Repayments in Year Four	0
Repayments in Year Five	825
Thereafter	7,240
Long-term Debt	9,258	$ 8,658
Power [Member]
Debt Instrument [Line Items]
Repayments in Next Twelve Months	44
Repayments in Year Two	406
Repayments in Year Three	950
Repayments in Year Four	0
Repayments in Year Five	950
Thereafter	500
Long-term Debt	2,850	2,400
PSEG [Member]
Debt Instrument [Line Items]
Repayments in Next Twelve Months	750
Repayments in Year Two	700
Repayments in Year Three	300
Repayments in Year Four	700
Repayments in Year Five	0
Thereafter	0
Long-term Debt	$ 2,450	$ 2,100

Debt and Credit Facilities (L_2

Debt and Credit Facilities (Long-Term Debt Financing Transactions) (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2018	Dec. 31, 2017
Debt Instrument [Line Items]
Long-term Debt		$ 14,558
PSEG [Member]
Debt Instrument [Line Items]
Long-term Debt		2,450	$ 2,100
PSEG [Member] | Term Loan maturing in 2020 [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount		700	0
PSEG [Member] | Term Loan maturing in 2019 [Member]
Debt Instrument [Line Items]
Long-term Debt		350	700
Repayments of Long-term Debt		350
PSE&G [Member] | Medium Term Notes Five Point Three Zero Percentage Due On Two Thousand Eighteen [Member]
Debt Instrument [Line Items]
Repayments of Long-term Debt		$ 400
PSE&G [Member] | Medium Term Notes Two Point Three Zero Percent Due In Two Thousand Eighteen [Member]
Debt Instrument [Line Items]
Stated interest rate of debt instrument		2.30%
Repayments of Long-term Debt		$ 350
PSE&G [Member] | Medium Term Notes Three Point Seven Zero Percent due Two Thousand Twenty Eight [Member]
Debt Instrument [Line Items]
Long-term Debt	[1]	375	0
Debt Instrument, Face Amount		$ 375
Stated interest rate of debt instrument		3.70%
PSE&G [Member] | Medium Term Notes Four Point Zero Five Percent due Two Thousand Forty Eight [Member]
Debt Instrument [Line Items]
Long-term Debt	[1]	$ 325	0
Debt Instrument, Face Amount		$ 325
Stated interest rate of debt instrument		4.05%
PSE&G [Member] | Medium Term Notes Three Point Two Five Percent due Two Thousand Twenty Three [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount	[1]	$ 325	0
Stated interest rate of debt instrument		3.25%
PSE&G [Member] | Medium Term Notes Three Point Six Five Percent due Two Thousand Twenty Eight [Member]
Debt Instrument [Line Items]
Long-term Debt	[1]	$ 325	0
Debt Instrument, Face Amount		$ 325
Stated interest rate of debt instrument		3.65%
PSE&G [Member] | Medium Term Notes Five Point Three Zero Percentage Due On Two Thousand Eighteen [Member]
Debt Instrument [Line Items]
Long-term Debt	[1]	$ 0	400
Stated interest rate of debt instrument		5.30%
PSE&G [Member] | Medium Term Notes Two Point Three Zero Percent Due In Two Thousand Eighteen [Member]
Debt Instrument [Line Items]
Long-term Debt	[1]	$ 0	350
Stated interest rate of debt instrument		2.30%
Power [Member]
Debt Instrument [Line Items]
Long-term Debt		$ 2,850	2,400
Power [Member] | Senior Notes Three Point Eight Five Percent due Two Thousand Twenty Three [Member]
Debt Instrument [Line Items]
Long-term Debt		700	0
Debt Instrument, Face Amount		$ 700
Stated interest rate of debt instrument		3.85%
Power [Member] | Senior Notes Two Point Four Five Percentage Due Two Thousand Eighteen [Member]
Debt Instrument [Line Items]
Long-term Debt		$ 0	$ 250
Stated interest rate of debt instrument		2.45%
Repayments of Long-term Debt		$ 250
[1]	Secured by essentially all property of PSE&G pursuant to its First and Refunding Mortgage.

Debt and Credit Facilities (Sho

Debt and Credit Facilities (Short-Term Liquidity) (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2018	Dec. 31, 2017
Short-term Debt [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity		$ 4,200
Line of Credit Facility, Amount Outstanding		1,201
Available Liquidity		2,999
Commercial Paper and Loans		$ 1,016	$ 542
Commitments of single institution as percentage of total commitments		9.00%
PSEG [Member]
Short-term Debt [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity		$ 1,500
Line of Credit Facility, Amount Outstanding		759
Available Liquidity		741
PSE&G [Member]
Short-term Debt [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity		600
Line of Credit Facility, Amount Outstanding		288
Available Liquidity		312
Commercial Paper and Loans		272	$ 0
Power [Member]
Short-term Debt [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity		2,100
Line of Credit Facility, Amount Outstanding		154
Available Liquidity		1,946
Revolving Credit Facility [Member] | PSEG [Member]
Short-term Debt [Line Items]
Commercial Paper and Loans		$ 744
Short-term Debt, Weighted Average Interest Rate, at Point in Time		2.95%
Revolving Credit Facility [Member] | PSE&G [Member]
Short-term Debt [Line Items]
Commercial Paper and Loans		$ 272
Short-term Debt, Weighted Average Interest Rate, at Point in Time		2.96%
Letter of Credit Facilities expiring September 2021 [Member] | Power [Member]
Short-term Debt [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity		$ 200
Line of Credit Facility, Amount Outstanding		114
Available Liquidity		$ 86
Expiration Date		Sept 2,021
Revolving Credit Facility [Member] | PSEG [Member]
Short-term Debt [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	[1]	$ 1,500
Line of Credit Facility, Amount Outstanding	[1]	759
Available Liquidity	[1]	$ 741
Expiration Date		Mar 2,022
Revolving Credit Facility [Member] | PSE&G [Member]
Short-term Debt [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	[1]	$ 600
Line of Credit Facility, Amount Outstanding	[1]	288
Available Liquidity	[1]	$ 312
Expiration Date		Mar 2,022
Revolving Credit Facility [Member] | Power [Member]
Short-term Debt [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity		$ 1,900
Line of Credit Facility, Amount Outstanding		40
Available Liquidity		$ 1,860
Expiration Date		Mar 2,022
[1]	The primary use of PSEG’s and PSE&G’s credit facilities is to support their respective Commercial Paper Programs under which as of December 31, 2018, PSEG had $744 million outstanding at a weighted average interest rate of 2.95%. PSE&G had $272 million outstanding at a weighted average interest rate of 2.96% under its Commercial Paper Program as of December 31, 2018.

Debt and Credit Facilities (Fai

Debt and Credit Facilities (Fair Value of Debt) (Details) - USD ($) $ in Millions		Dec. 31, 2018	Dec. 31, 2017
Debt Instrument [Line Items]
Long-term Debt		$ 14,558
Long-term Debt, Carrying Value		14,462	$ 13,068
Long-term Debt, Fair Value		14,767	14,062
PSEG [Member]
Debt Instrument [Line Items]
Long-term Debt		2,450	2,100
Long-term Debt, Carrying Value		2,443	2,091
Long-term Debt, Fair Value	[1],[2]	2,397	2,081
PSE&G
Debt Instrument [Line Items]
Long-term Debt		9,258	8,658
Long-term Debt, Carrying Value		9,184	8,591
Long-term Debt, Fair Value	[2]	9,374	9,322
Power [Member]
Debt Instrument [Line Items]
Long-term Debt		2,850	2,400
Long-term Debt, Carrying Value		2,835	2,386
Long-term Debt, Fair Value	[2]	2,996	2,659
Loans Payable [Member] | PSEG [Member]
Debt Instrument [Line Items]
Long-term Debt		$ 1,050	$ 700
[1]	As of December 31, 2018 and 2017, fair value includes floating rate term loans of $1,050 million and $700 million, respectively. The fair value of the term loan debt (Level 2 measurement) approximates the carrying value because the interest payments are based on LIBOR rates that are reset monthly and the debt is redeemable at face value by PSEG at any time.
[2]	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.

Schedule Of Consolidated Capi_3

Schedule Of Consolidated Capital Stock (Consolidated Capital Stock) (Details) - USD ($) $ / shares in Units, $ in Millions		Dec. 31, 2018	Dec. 31, 2017
Class of Stock [Line Items]
Common Stock, authorized		1,000,000,000	1,000,000,000
Common Stock, Shares, outstanding	[1]	504	505
Common Stock, Value, Outstanding	[1]	$ 4,172	$ 4,198
PSE&G [Member]
Class of Stock [Line Items]
Common Stock, authorized		150,000,000	150,000,000
PSE&G [Member] | Preferred Stock [Member]
Class of Stock [Line Items]
Common Stock, authorized		7,500,000
Preferred stock, par value		$ 100
PSE&G [Member] | Cumulative Preferred Stock [Member]
Class of Stock [Line Items]
Common Stock, authorized		10,000,000
Preferred stock, par value		$ 25
[1]	PSEG did not issue any new shares under the Dividend Reinvestment and Stock Purchase Plan (DRASPP) or the Employee Stock Purchase Plan (ESPP) in 2018 or 2017.

Financial Risk Management Act_3

Financial Risk Management Activities (Narrative) (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Derivatives, Fair Value [Line Items]
Other Comprehensive Income before Reclassifications	$ (9)	$ 77	$ (3)
Floating Rate term loans	14,558
Net cash collateral received in connection with net derivative contracts	153	44
Accumulated Other Comprehensive Income (Loss) on interest rate derivatives	(1)		2
PSEG [Member]
Derivatives, Fair Value [Line Items]
Floating Rate term loans	2,450	2,100
Amount of reduction in interest expense attributed to interest rate swaps designated as fair value hedges			6
Power [Member]
Derivatives, Fair Value [Line Items]
Net Credit Exposure With Counterparties After Applying Collateral	253
Other Comprehensive Income before Reclassifications	(3)	78	$ (3)
Floating Rate term loans	2,850	2,400
Credit Risk Derivative Liabilities, at Fair Value	22	30
Aggregate fair value of derivative contracts in a liability position that contains triggers for additional collateral	7	13
Additional collateral aggregate fair value	$ 15	17
Power [Member] | Senior Notes Three Point Eight Five Percent due Two Thousand Twenty Three [Member]
Derivatives, Fair Value [Line Items]
Stated interest rate of debt instrument	3.85%
Floating Rate term loans	$ 700	$ 0
Debt Instrument, Face Amount	700
Cash Flow Hedging [Member] | PSEG [Member]
Derivatives, Fair Value [Line Items]
Aggregate amount of series of interest rate swaps converting to variable-rate debt	$ 500

Financial Risk Management Act_4

Financial Risk Management Activities (Schedule Of Derivative Instruments Fair Value In Balance Sheets) (Detail) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Derivatives, Fair Value [Line Items]
Net Cash Collateral/Margin Postings to Counterparties	$ 393	$ 146
Derivative, Fair Value, Amount Offset Against Collateral, Net	153	44
Derivative Contracts, Current Assets	11	29
Derivative Contracts, Noncurrent Assets	1	7
Total Mark-to-Market Derivative Assets	12	36
Derivative Contracts, Current Liabilities	(11)	(16)
Derivative Contracts, Noncurrent Liabilities	(4)	(5)
Total Mark-to-Market Derivative (Liabilities)	(15)	(21)
Net Mark-to-Market Derivative Assets (Liabilities)	(3)	15
Power [Member]
Derivatives, Fair Value [Line Items]
Derivative Contracts, Current Assets	11	29	[1]
Derivative Contracts, Noncurrent Assets	1	7	[1]
Total Mark-to-Market Derivative Assets	12	36	[1]
Derivative Contracts, Current Liabilities	(11)	(16)	[1]
Derivative Contracts, Noncurrent Liabilities	(4)	(5)	[1]
Total Mark-to-Market Derivative (Liabilities)	(15)	(21)	[1]
Net Mark-to-Market Derivative Assets (Liabilities)	(3)	15	[1]
Power [Member] | Netting [Member]
Derivatives, Fair Value [Line Items]
Total Mark-to-Market Derivative Assets	(551)	(433)	[1],[2]
Total Mark-to-Market Derivative (Liabilities)	704	477	[1]
Net Mark-to-Market Derivative Assets (Liabilities)	153	44	[1],[2]
Current Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative, Fair Value, Amount Offset Against Collateral, Net	(2)	(3)
Current Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative, Fair Value, Amount Offset Against Collateral, Net	96	28
Noncurrent Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative, Fair Value, Amount Offset Against Collateral, Net	62	19
Noncurrent Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative, Fair Value, Amount Offset Against Collateral, Net	(3)
Energy-Related Contracts [Member] | Not Designated as Hedging Instrument [Member] | Power [Member]
Derivatives, Fair Value [Line Items]
Derivative Contracts, Current Assets	426	391	[1]
Derivative Contracts, Noncurrent Assets	137	78	[1]
Total Mark-to-Market Derivative Assets	563	469	[1]
Derivative Contracts, Current Liabilities	(521)	(403)	[1]
Derivative Contracts, Noncurrent Liabilities	(198)	(95)	[1]
Total Mark-to-Market Derivative (Liabilities)	(719)	(498)	[1]
Net Mark-to-Market Derivative Assets (Liabilities)	(156)	(29)	[1]
Energy-Related Contracts [Member] | Current Assets [Member] | Power [Member]
Derivatives, Fair Value [Line Items]
Derivative, Fair Value, Amount Offset Against Collateral, Net	(415)	(362)	[1],[2]
Energy-Related Contracts [Member] | Current Liabilities [Member] | Power [Member]
Derivatives, Fair Value [Line Items]
Derivative, Fair Value, Amount Offset Against Collateral, Net	510	387	[1],[2]
Energy-Related Contracts [Member] | Noncurrent Liabilities [Member] | Power [Member]
Derivatives, Fair Value [Line Items]
Derivative, Fair Value, Amount Offset Against Collateral, Net	194	90	[1],[2]
Energy-Related Contracts [Member] | Noncurrent Assets [Member] | Power [Member]
Derivatives, Fair Value [Line Items]
Derivative, Fair Value, Amount Offset Against Collateral, Net	$ (136)	$ (71)	[1],[2]
[1]	Substantially all of Power's derivative instruments are contracts subject to master netting agreements. Contracts not subject to master netting or similar agreements are immaterial and did not have any collateral posted or received as of December 31, 2018 and 2017. PSE&G does not have any derivative contracts subject to master netting or similar agreements.
[2]	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 Consolidated Balance Sheets. As of December 31, 2018 and 2017, Power had net cash collateral/margin payments to counterparties of $393 million and $146 million, respectively. Of these net cash collateral/margin payments, $153 million as of December 31, 2018 and $44 million as of December 31, 2017 were netted against the corresponding net derivative contract positions. Of the $153 million as of December 31, 2018, $(2) million was netted against current assets, $(3) million was netted against noncurrent assets, $96 million was netted against current liabilities and $62 million was netted against noncurrent liabilities. 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.

Financial Risk Management Act_5

Financial Risk Management Activities (Schedule Of Derivative Instruments Designated As Cash Flow Hedges) (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Pre-Tax Gain (Loss) attributed to Cash Flow Hedges Recognized in AOCI on Derivatives (Effective Portion)	$ (2)	$ 0	$ 3
Amount of Pre-Tax Gain (Loss) Reclassified from AOCI into Income, Effective Portion	0	(3)	0
Interest Expense [Member] | Interest Rate Swaps [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Pre-Tax Gain (Loss) attributed to Cash Flow Hedges Recognized in AOCI on Derivatives (Effective Portion)	(2)	0	3
Amount of Pre-Tax Gain (Loss) Reclassified from AOCI into Income, Effective Portion	$ 0	$ (3)	$ 0

Financial Risk Management Act_6

Financial Risk Management Activities (Schedule Of Reconciliation For Derivative Activity Included In Accumulated Other Comprehensive Loss) (Detail) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Jun. 30, 2018	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Derivative [Line Items]
Gain (Loss) Recognized in AOCI, After-Tax		$ (9)	$ 77	$ (3)
Less: Gain Reclassified to Income, After-Tax		37	(43)	35
Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member]
Derivative [Line Items]
Balance as of Beginning of Year		0	3
Gain (Loss) Recognized in AOCI, Pre-Tax		(2)	0
Less: Gain Reclassified into Income, Pre-Tax		0	(3)
Balance as of End of Year		(2)	0	3
Balance as of Beginning of Year		0	2
Gain (Loss) Recognized in AOCI, After-Tax	$ (1)	(1)	0	2
Less: Gain Reclassified to Income, After-Tax		0	(2)	0
Balance as of End of Year		$ (1)	$ 0	$ 2

Financial Risk Management Act_7

Financial Risk Management Activities (Schedule Of Derivative Instruments Not Designated As Hedging Instruments And Impact On Results Of Operations) (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Derivative Instruments, Gain (Loss) [Line Items]
Pre-Tax Gain (Loss) Recognized in Income on Derivatives	$ (191)	$ 55	$ 222
Operating Revenues [Member] | Energy-Related Contracts [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Pre-Tax Gain (Loss) Recognized in Income on Derivatives	(182)	66	218
Energy Costs [Member] | Energy-Related Contracts [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Pre-Tax Gain (Loss) Recognized in Income on Derivatives	$ (9)	$ (11)	$ 4

Financial Risk Management Act_8

Financial Risk Management Activities (Schedule Of Gross Volume, On Absolute Basis For Derivative Contracts) (Detail) $ / mwh in Millions, $ / DTH in Millions	12 Months Ended
	Dec. 31, 2018$ / mwh$ / DTH	Dec. 31, 2017$ / mwh$ / DTH
Natural Gas Dth [Member]
Derivative [Line Items]
Gross volume of derivative on absolute value basis	358	154
Electricity MWh [Member]
Derivative [Line Items]
Gross volume of derivative on absolute value basis	74	63
FTRs MWh [Member]
Derivative [Line Items]
Gross volume of derivative on absolute value basis	18	6
PSEG [Member] | Natural Gas Dth [Member]
Derivative [Line Items]
Gross volume of derivative on absolute value basis	0	0
PSEG [Member] | Electricity MWh [Member]
Derivative [Line Items]
Gross volume of derivative on absolute value basis	0
PSEG [Member] | FTRs MWh [Member]
Derivative [Line Items]
Gross volume of derivative on absolute value basis	0	0
Power [Member] | Natural Gas Dth [Member]
Derivative [Line Items]
Gross volume of derivative on absolute value basis | $ / DTH	358	154
Power [Member] | Electricity MWh [Member]
Derivative [Line Items]
Gross volume of derivative on absolute value basis	74	63
Power [Member] | FTRs MWh [Member]
Derivative [Line Items]
Gross volume of derivative on absolute value basis	18	6
PSE&G [Member] | Natural Gas Dth [Member]
Derivative [Line Items]
Gross volume of derivative on absolute value basis | $ / DTH	0	0
PSE&G [Member] | Electricity MWh [Member]
Derivative [Line Items]
Gross volume of derivative on absolute value basis	0	0
PSE&G [Member] | FTRs MWh [Member]
Derivative [Line Items]
Gross volume of derivative on absolute value basis	0	0

Financial Risk Management Act_9

Financial Risk Management Activities (Schedule Providing Credit Risk From Others, Net Of Collateral) (Detail) - Power [Member] $ in Millions	12 Months Ended
	Dec. 31, 2018USD ($)Counterparty
Derivative [Line Items]
Current Exposure	$ 265
Collateral held from counterparties	12
Net Credit Exposure With Counterparties After Applying Collateral	253
Number of Counterparties greater than 10%	1
Net Exposure of Counterparties greater than 10%	$ 179
Number of active counterparties on credit risk derivatives | Counterparty	151
Investment Grade External Rating [Member]
Derivative [Line Items]
Credit exposure, percentage	99.00%
Investment Grade [Member]
Derivative [Line Items]
Current Exposure	$ 264
Collateral held from counterparties	12
Net Credit Exposure With Counterparties After Applying Collateral	252
Number of Counterparties greater than 10%	1
Net Exposure of Counterparties greater than 10%	179	[1]
Non-Investment Grade [Member]
Derivative [Line Items]
Current Exposure	1
Collateral held from counterparties	0
Net Credit Exposure With Counterparties After Applying Collateral	1
Number of Counterparties greater than 10%	0
Net Exposure of Counterparties greater than 10%	0
Letter of Credit [Member]
Derivative [Line Items]
Collateral held from counterparties	$ 12
[1]	Represents net exposure with PSE&G.

Fair Value Measurements (PSEG's

Fair Value Measurements (PSEG's, Power's And PSE&G's Respective Assets And (Liabilities) Measured At Fair Value On A Recurring Basis) (Detail) - USD ($) $ in Millions		Dec. 31, 2018		Dec. 31, 2017
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Collateral Already Posted, Aggregate Fair Value		$ 393		$ 146
Derivative, Fair Value, Amount Offset Against Collateral, Net		153		44
Total Mark-to-Market Derivative Assets		12		36
Total Mark-to-Market Derivative (Liabilities)		(15)		(21)
Equity Securities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative, Fair Value, Amount Offset Against Collateral, Net	[1]	0		0	[2]
Government Obligations [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative, Fair Value, Amount Offset Against Collateral, Net	[1]	0		0	[2]
US Treasury Obligations [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative, Fair Value, Amount Offset Against Collateral, Net	[1]	0		0	[2]
Corporate Debt Securities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative, Fair Value, Amount Offset Against Collateral, Net	[1]	0		0	[2]
Rabbi Trust - Equity Securities-Mutual Funds [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative, Fair Value, Amount Offset Against Collateral, Net	[1]	0		0	[2]
Rabbi Trust - Debt Securities-Govt Obligations [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative, Fair Value, Amount Offset Against Collateral, Net	[1]	0		0	[2]
Rabbi Trusts US Treasury Obligations [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative, Fair Value, Amount Offset Against Collateral, Net	[1]	0		0	[2]
Rabbi Trust - Debt Securities-Corporate [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative, Fair Value, Amount Offset Against Collateral, Net	[1]	0		0	[2]
Power [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total Mark-to-Market Derivative Assets		12		36	[3]
Total Mark-to-Market Derivative (Liabilities)		(15)		(21)	[3]
Power [Member] | Equity Securities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative, Fair Value, Amount Offset Against Collateral, Net	[1]	0		0	[2]
Power [Member] | Government Obligations [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative, Fair Value, Amount Offset Against Collateral, Net	[1]	0		0	[2]
Power [Member] | US Treasury Obligations [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative, Fair Value, Amount Offset Against Collateral, Net	[1]	0		0	[2]
Power [Member] | Corporate Debt Securities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative, Fair Value, Amount Offset Against Collateral, Net	[1]	0		0	[2]
Power [Member] | Rabbi Trust - Equity Securities-Mutual Funds [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative, Fair Value, Amount Offset Against Collateral, Net	[1]	0		0	[2]
Power [Member] | Rabbi Trust - Debt Securities-Govt Obligations [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative, Fair Value, Amount Offset Against Collateral, Net	[1]	0		0	[2]
Power [Member] | Rabbi Trusts US Treasury Obligations [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative, Fair Value, Amount Offset Against Collateral, Net	[1]	0		0	[2]
Power [Member] | Rabbi Trust - Debt Securities-Corporate [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative, Fair Value, Amount Offset Against Collateral, Net	[1]	0		0	[2]
PSE&G [Member] | Rabbi Trust - Equity Securities-Mutual Funds [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative, Fair Value, Amount Offset Against Collateral, Net	[1]	0		0	[2]
PSE&G [Member] | Rabbi Trust - Debt Securities-Govt Obligations [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative, Fair Value, Amount Offset Against Collateral, Net	[1]	0		0	[2]
PSE&G [Member] | Rabbi Trusts US Treasury Obligations [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative, Fair Value, Amount Offset Against Collateral, Net	[1]	0		0	[2]
PSE&G [Member] | Rabbi Trust - Debt Securities-Corporate [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative, Fair Value, Amount Offset Against Collateral, Net	[1]	0		0	[2]
Quoted Market Prices for Identical Assets (Level 1) [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash Equivalents	[4]	100		223
Quoted Market Prices for Identical Assets (Level 1) [Member] | Equity Securities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[1]	898		1,145
Quoted Market Prices for Identical Assets (Level 1) [Member] | Government Obligations [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[1]	0		0
Quoted Market Prices for Identical Assets (Level 1) [Member] | US Treasury Obligations [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[1]	0		0
Quoted Market Prices for Identical Assets (Level 1) [Member] | Corporate Debt Securities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[1]	0		0
Quoted Market Prices for Identical Assets (Level 1) [Member] | Rabbi Trust - Equity Securities-Mutual Funds [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[1]	23		27
Quoted Market Prices for Identical Assets (Level 1) [Member] | Rabbi Trust - Debt Securities-Govt Obligations [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[1]			0
Quoted Market Prices for Identical Assets (Level 1) [Member] | Rabbi Trusts US Treasury Obligations [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[1]	0		0
Quoted Market Prices for Identical Assets (Level 1) [Member] | Rabbi Trust - Debt Securities-Corporate [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[1]	0		0
Quoted Market Prices for Identical Assets (Level 1) [Member] | Power [Member] | Equity Securities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[1]	898		1,145
Quoted Market Prices for Identical Assets (Level 1) [Member] | Power [Member] | Government Obligations [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[1]	0		0
Quoted Market Prices for Identical Assets (Level 1) [Member] | Power [Member] | US Treasury Obligations [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[1]	0		0
Quoted Market Prices for Identical Assets (Level 1) [Member] | Power [Member] | Corporate Debt Securities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[1]	0		0
Quoted Market Prices for Identical Assets (Level 1) [Member] | Power [Member] | Rabbi Trust - Equity Securities-Mutual Funds [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[1]	6		6
Quoted Market Prices for Identical Assets (Level 1) [Member] | Power [Member] | Rabbi Trust - Debt Securities-Govt Obligations [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[1]	0		0
Quoted Market Prices for Identical Assets (Level 1) [Member] | Power [Member] | Rabbi Trusts US Treasury Obligations [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[1]	0		0
Quoted Market Prices for Identical Assets (Level 1) [Member] | Power [Member] | Rabbi Trust - Debt Securities-Corporate [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[1]	0		0
Quoted Market Prices for Identical Assets (Level 1) [Member] | PSE&G [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash Equivalents				223
Quoted Market Prices for Identical Assets (Level 1) [Member] | PSE&G [Member] | Rabbi Trust - Equity Securities-Mutual Funds [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[1]	5		5
Quoted Market Prices for Identical Assets (Level 1) [Member] | PSE&G [Member] | Rabbi Trust - Debt Securities-Govt Obligations [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[1]	0		0
Quoted Market Prices for Identical Assets (Level 1) [Member] | PSE&G [Member] | Rabbi Trusts US Treasury Obligations [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[1]	0		0
Quoted Market Prices for Identical Assets (Level 1) [Member] | PSE&G [Member] | Rabbi Trust - Debt Securities-Corporate [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[1]	0		0
Significant Other Observable Inputs (Level 2) [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash Equivalents		0	[4]	0
Significant Other Observable Inputs (Level 2) [Member] | Equity Securities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[1]	2		2
Significant Other Observable Inputs (Level 2) [Member] | Government Obligations [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[1]	171		270
Significant Other Observable Inputs (Level 2) [Member] | US Treasury Obligations [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[1]	320		314
Significant Other Observable Inputs (Level 2) [Member] | Corporate Debt Securities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[1]	487		402
Significant Other Observable Inputs (Level 2) [Member] | Rabbi Trust - Equity Securities-Mutual Funds [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[1]	0		0
Significant Other Observable Inputs (Level 2) [Member] | Rabbi Trust - Debt Securities-Govt Obligations [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[1]	40		34
Significant Other Observable Inputs (Level 2) [Member] | Rabbi Trusts US Treasury Obligations [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[1]	69		51
Significant Other Observable Inputs (Level 2) [Member] | Rabbi Trust - Debt Securities-Corporate [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[1]	92		119
Significant Other Observable Inputs (Level 2) [Member] | Power [Member] | Equity Securities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[1]	2		2
Significant Other Observable Inputs (Level 2) [Member] | Power [Member] | Government Obligations [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[1]	320		270
Significant Other Observable Inputs (Level 2) [Member] | Power [Member] | US Treasury Obligations [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[1]	171		314
Significant Other Observable Inputs (Level 2) [Member] | Power [Member] | Corporate Debt Securities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[1]	487		402
Significant Other Observable Inputs (Level 2) [Member] | Power [Member] | Rabbi Trust - Equity Securities-Mutual Funds [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[1]	0		0
Significant Other Observable Inputs (Level 2) [Member] | Power [Member] | Rabbi Trust - Debt Securities-Govt Obligations [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[1]	10		8
Significant Other Observable Inputs (Level 2) [Member] | Power [Member] | Rabbi Trusts US Treasury Obligations [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[1]	17		13
Significant Other Observable Inputs (Level 2) [Member] | Power [Member] | Rabbi Trust - Debt Securities-Corporate [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[1]	23		30
Significant Other Observable Inputs (Level 2) [Member] | PSE&G [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash Equivalents				0
Significant Other Observable Inputs (Level 2) [Member] | PSE&G [Member] | Rabbi Trust - Equity Securities-Mutual Funds [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[1]	0		0
Significant Other Observable Inputs (Level 2) [Member] | PSE&G [Member] | Rabbi Trust - Debt Securities-Govt Obligations [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[1]	8		7
Significant Other Observable Inputs (Level 2) [Member] | PSE&G [Member] | Rabbi Trusts US Treasury Obligations [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[1]	14		10
Significant Other Observable Inputs (Level 2) [Member] | PSE&G [Member] | Rabbi Trust - Debt Securities-Corporate [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[1]	18		24
Significant Unobservable Inputs (Level 3) [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash Equivalents	[4]	0		0
Significant Unobservable Inputs (Level 3) [Member] | Equity Securities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[1]	0		0
Significant Unobservable Inputs (Level 3) [Member] | Government Obligations [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[1]	0		0
Significant Unobservable Inputs (Level 3) [Member] | US Treasury Obligations [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[1]	0		0
Significant Unobservable Inputs (Level 3) [Member] | Corporate Debt Securities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[1]	0		0
Significant Unobservable Inputs (Level 3) [Member] | Rabbi Trust - Equity Securities-Mutual Funds [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[1]	0		0
Significant Unobservable Inputs (Level 3) [Member] | Rabbi Trust - Debt Securities-Govt Obligations [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[1]			0
Significant Unobservable Inputs (Level 3) [Member] | Rabbi Trusts US Treasury Obligations [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[1]	0		0
Significant Unobservable Inputs (Level 3) [Member] | Rabbi Trust - Debt Securities-Corporate [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[1]	0		0
Significant Unobservable Inputs (Level 3) [Member] | Power [Member] | Equity Securities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[1]	0		0
Significant Unobservable Inputs (Level 3) [Member] | Power [Member] | Government Obligations [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[1]	0		0
Significant Unobservable Inputs (Level 3) [Member] | Power [Member] | US Treasury Obligations [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[1]	0		0
Significant Unobservable Inputs (Level 3) [Member] | Power [Member] | Corporate Debt Securities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[1]	0		0
Significant Unobservable Inputs (Level 3) [Member] | Power [Member] | Rabbi Trust - Equity Securities-Mutual Funds [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[1]	0		0
Significant Unobservable Inputs (Level 3) [Member] | Power [Member] | Rabbi Trust - Debt Securities-Govt Obligations [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[1]	0		0
Significant Unobservable Inputs (Level 3) [Member] | Power [Member] | Rabbi Trusts US Treasury Obligations [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[1]	0		0
Significant Unobservable Inputs (Level 3) [Member] | Power [Member] | Rabbi Trust - Debt Securities-Corporate [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[1]	0		0
Significant Unobservable Inputs (Level 3) [Member] | PSE&G [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash Equivalents				0
Significant Unobservable Inputs (Level 3) [Member] | PSE&G [Member] | Rabbi Trust - Equity Securities-Mutual Funds [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[1]	0		0
Significant Unobservable Inputs (Level 3) [Member] | PSE&G [Member] | Rabbi Trust - Debt Securities-Govt Obligations [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[1]	0		0
Significant Unobservable Inputs (Level 3) [Member] | PSE&G [Member] | Rabbi Trusts US Treasury Obligations [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[1]	0		0
Significant Unobservable Inputs (Level 3) [Member] | PSE&G [Member] | Rabbi Trust - Debt Securities-Corporate [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[1]	0		0
Energy-Related Contracts [Member] | Quoted Market Prices for Identical Assets (Level 1) [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total Mark-to-Market Derivative Assets	[5]	29		15
Total Mark-to-Market Derivative (Liabilities)	[5]	(36)		(8)
Energy-Related Contracts [Member] | Quoted Market Prices for Identical Assets (Level 1) [Member] | Power [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total Mark-to-Market Derivative Assets		29	[5]	15
Total Mark-to-Market Derivative (Liabilities)		(36)	[5]	(8)
Energy-Related Contracts [Member] | Significant Other Observable Inputs (Level 2) [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total Mark-to-Market Derivative Assets	[5]	527		442
Total Mark-to-Market Derivative (Liabilities)	[5]	(677)		(485)
Energy-Related Contracts [Member] | Significant Other Observable Inputs (Level 2) [Member] | Power [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total Mark-to-Market Derivative Assets		527	[5]	442
Total Mark-to-Market Derivative (Liabilities)		(677)	[5]	485
Energy-Related Contracts [Member] | Significant Unobservable Inputs (Level 3) [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total Mark-to-Market Derivative Assets	[5]	7		12
Total Mark-to-Market Derivative (Liabilities)	[5]	(6)		(5)
Energy-Related Contracts [Member] | Significant Unobservable Inputs (Level 3) [Member] | Power [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total Mark-to-Market Derivative Assets		7	[5]	12
Total Mark-to-Market Derivative (Liabilities)		(6)	[5]	(5)
Cash and Cash Equivalents [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative, Fair Value, Amount Offset Against Collateral, Net	[4]	0		0	[2]
Cash and Cash Equivalents [Member] | PSE&G [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative, Fair Value, Amount Offset Against Collateral, Net				0
Assets [Member] | Energy-Related Contracts [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative, Fair Value, Amount Offset Against Collateral, Net	[5]	(551)		(433)	[2]
Assets [Member] | Energy-Related Contracts [Member] | Power [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative, Fair Value, Amount Offset Against Collateral, Net		(551)	[5]	(433)
Other Liabilities [Member] | Energy-Related Contracts [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative, Fair Value, Amount Offset Against Collateral, Net	[5]	704		477	[2]
Other Liabilities [Member] | Energy-Related Contracts [Member] | Power [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative, Fair Value, Amount Offset Against Collateral, Net		704	[5]	477
Total Estimate Of Fair Value [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash Equivalents	[4]	100		223
Total Estimate Of Fair Value [Member] | Equity Securities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[1]	900		1,147
Total Estimate Of Fair Value [Member] | Government Obligations [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[1]	320		270
Total Estimate Of Fair Value [Member] | US Treasury Obligations [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[1]	171		314
Total Estimate Of Fair Value [Member] | Corporate Debt Securities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[1]	487		402
Total Estimate Of Fair Value [Member] | Rabbi Trust - Equity Securities-Mutual Funds [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[1]	23		27
Total Estimate Of Fair Value [Member] | Rabbi Trust - Debt Securities-Govt Obligations [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[1]	40		34
Total Estimate Of Fair Value [Member] | Rabbi Trusts US Treasury Obligations [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[1]	69		51
Total Estimate Of Fair Value [Member] | Rabbi Trust - Debt Securities-Corporate [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[1]	92		119
Total Estimate Of Fair Value [Member] | Power [Member] | Equity Securities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[1]	900		1,147
Total Estimate Of Fair Value [Member] | Power [Member] | Government Obligations [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[1]	320		270
Total Estimate Of Fair Value [Member] | Power [Member] | US Treasury Obligations [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[1]	171		314
Total Estimate Of Fair Value [Member] | Power [Member] | Corporate Debt Securities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[1]	487		402
Total Estimate Of Fair Value [Member] | Power [Member] | Rabbi Trust - Equity Securities-Mutual Funds [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[1]	6		6
Total Estimate Of Fair Value [Member] | Power [Member] | Rabbi Trust - Debt Securities-Govt Obligations [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[1]	10		8
Total Estimate Of Fair Value [Member] | Power [Member] | Rabbi Trusts US Treasury Obligations [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[1]	17		13
Total Estimate Of Fair Value [Member] | Power [Member] | Rabbi Trust - Debt Securities-Corporate [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[1]	23		30
Total Estimate Of Fair Value [Member] | PSE&G [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash Equivalents	[4]			223
Total Estimate Of Fair Value [Member] | PSE&G [Member] | Rabbi Trust - Equity Securities-Mutual Funds [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[1]	5		5
Total Estimate Of Fair Value [Member] | PSE&G [Member] | Rabbi Trust - Debt Securities-Govt Obligations [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[1]	8		7
Total Estimate Of Fair Value [Member] | PSE&G [Member] | Rabbi Trusts US Treasury Obligations [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[1]	14		10
Total Estimate Of Fair Value [Member] | PSE&G [Member] | Rabbi Trust - Debt Securities-Corporate [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured on Recurring Basis, Investments	[1]	18		24
Total Estimate Of Fair Value [Member] | Energy-Related Contracts [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total Mark-to-Market Derivative Assets	[5]	12		36
Total Mark-to-Market Derivative (Liabilities)	[5]	(15)		(21)
Total Estimate Of Fair Value [Member] | Energy-Related Contracts [Member] | Power [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total Mark-to-Market Derivative Assets	[5]	12		36
Total Mark-to-Market Derivative (Liabilities)	[5]	$ (15)		$ (21)
[1]	Represents the netting of fair value balances with the same counterparty (where the right of offset exists) and the application of collateral. See Note 17. Financial Risk Management Activities for additional detail.
[2]	{F|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOjU2MjJmZDQ1MzAxZjQzNzFiZjAwOWNmODVlNDI0MTI5fFRleHRTZWxlY3Rpb246RTAwOTkwMTgzODNBRUE5QkUxQkNEOTVBODFDN0I5MTQM}
[3]	Substantially all of Power's derivative instruments are contracts subject to master netting agreements. Contracts not subject to master netting or similar agreements are immaterial and did not have any collateral posted or received as of December 31, 2018 and 2017. PSE&G does not have any derivative contracts subject to master netting or similar agreements.
[4]	Represents money market mutual funds.
[5]	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 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.

Fair Value Measurements (Schedu

Fair Value Measurements (Schedule Of Quantitative Information About Level 3 Fair Value Measurements) (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Fair Value Inputs, Assets, Quantitative Information [Line Items] (Deprecated 2018-01-31)
Assets, Fair Value Disclosure	$ 7	$ 12
Liabilities, Fair Value Disclosure	(6)	(5)
Power [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items] (Deprecated 2018-01-31)
Assets, Fair Value Disclosure	7	12
Liabilities, Fair Value Disclosure	(6)	(5)
Electric Load Contracts [Member] | Power [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items] (Deprecated 2018-01-31)
Assets, Fair Value Disclosure	2	1
Liabilities, Fair Value Disclosure	$ (5)	$ (3)
Valuation Technique used	Discounted Cash flow	Discounted Cash flow
Fair Value Measurement With Significant Unobservable Inputs	Historic Load Variability	Historic Load Variability
Electric Load Contracts [Member] | Power [Member] | Minimum [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items] (Deprecated 2018-01-31)
Historic Load Variability	0.00%	0.00%
Electric Load Contracts [Member] | Power [Member] | Maximum [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items] (Deprecated 2018-01-31)
Historic Load Variability	15.00%	10.00%
Gas Physical Contract [Member] | Power [Member] | Minimum [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items] (Deprecated 2018-01-31)
Average Historical Basis	(40.00%)	(40.00%)
Gas Physical Contract [Member] | Power [Member] | Maximum [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items] (Deprecated 2018-01-31)
Average Historical Basis	0.00%	(10.00%)
Various [Member] | Power [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items] (Deprecated 2018-01-31)
Assets, Fair Value Disclosure	$ 5	$ 11
Liabilities, Fair Value Disclosure	$ (1)	$ (2)

Fair Value Measurements (Change

Fair Value Measurements (Changes In Level 3 Assets And (Liabilities) Measured At Fair Value On A Recurring Basis) (Detail) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2018		Dec. 31, 2017
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Included in Income	[1]	$ (6)		$ 26
Transfers In (Out)				(1)
Settlements				24
Net Assets Measured At Fair Value On A Recurring Basis		2,200		2,600
Net Assets Measured At Fair Value On A Recurring Basis Measured Using Unobservable Input And Classified As Level3		1		7
Unrealized Gains (Losses)		(6)		3
Net Derivative Assets (Liabilities) [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Opening Balance		7		1
Included in Income	[1]	(6)		26
Included in Regulatory Assets/Liabilities	[2]	0		5
Purchases, (Sales)		0		0
Issuances (Settlements)	[3]	0		(24)
Transfers In (Out)		0	[4]	(1)
Closing Balance		1		7
Net Derivative Assets (Liabilities) [Member] | Power [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Opening Balance		7		6
Included in Income	[1]	(6)		26
Included in Regulatory Assets/Liabilities	[2]	0		0
Purchases, (Sales)		0		0
Issuances (Settlements)	[3]	0		(24)
Transfers In (Out)		0	[4]	(1)
Closing Balance		1		7
Net Derivative Assets (Liabilities) [Member] | PSE&G [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Opening Balance		0		(5)
Included in Income	[1]			0
Included in Regulatory Assets/Liabilities	[2]			5
Purchases, (Sales)				0
Issuances (Settlements)	[3]			0
Transfers In (Out)				0
Closing Balance				0
Operating Revenues [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Included in Income	[1]	(2)		14
Unrealized Gains (Losses)		0		(9)
Energy Costs [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Included in Income	[1]	(4)		12
Unrealized Gains (Losses)		$ (6)		$ 12
[1]	Unrealized gains (losses) in the following table represent the change in derivative assets and liabilities still held as of December 31, 2018 and 2017.
[2]	(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 custom
[3]	Represents $(24) million in settlements for derivative contracts in 2017.
[4]	During the year ended December 31, 2017, $(1) million of net derivatives assets/liabilities were transferred from Level 2 to Level 3. There were no transfers in 2018.

Fair Value Measurements (Narrat

Fair Value Measurements (Narrative) (Detail) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Fair Value Disclosures [Abstract]
Net Assets Measured At Fair Value On A Recurring Basis	$ 2,200	$ 2,600
Net Assets Measured At Fair Value On A Recurring Basis Measured Using Unobservable Input And Classified As Level3	$ 1	$ 7

Stock Based Compensation (Accru

Stock Based Compensation (Accrual Adjustments) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Compensation Cost included in Operation and Maintenance Expense	$ 30	$ 31	$ 29
Income Tax Benefit Recognized in Consolidated Statement of Operations	9	13	12
Excess Tax Benefits	$ 3	$ 4	$ 4

Stock Based Compensation (Stock

Stock Based Compensation (Stock Option Activity) (Details)	12 Months Ended
	Dec. 31, 2018USD ($)$ / sharesshares
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]
Options, Beginning of Year | shares	347,900
Options, Exercised | shares	115,967
Options, Canceled/Forfeited | shares	0
Options, End of Year | shares	231,933
Options, Exercisable at End of Year | shares	231,933
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price [Roll Forward]
Options, Beginning of Year, Weighted Average Exercise Price | $ / shares	$ 33.49
Options, Exercised, Weighted Average Exercise Price | $ / shares	33.49
Options, Forfeitures and Expirations in Period, Weighted Average Exercise Price | $ / shares	0
Options, End of Year, Weighted Average Exercise Price | $ / shares	33.49
Options, Exercisable at End of Year, Weighted Average Exercise Price | $ / shares	$ 33.49
Options, Outstanding at End of Year, Weighted Average Remaining Years Contractual Term	11 months 14 days
Options, Exercisable at End of Year, Weighted Average Remaining Years Contractual Term	11 months 14 days
Options, Outstanding at End of Year, Aggregate Intrinsic Value | $	$ 4,304,676
Options, Exercisable at End of Year, Aggregate Intrinsic Value | $	$ 4,304,676

Stock Based Compensation (Optio

Stock Based Compensation (Options Exercised) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Total Intrinsic Value of Options Exercised	$ 2	$ 5	$ 7
Cash Received from Options Exercised	4	26	22
Tax Benefit Realized from Options Exercised	$ 0	$ 0	$ 1

Stock Based Compensation (Restr

Stock Based Compensation (Restricted Stock Units Activity) (Details) - Restricted Stock Units (RSUs) [Member] - $ / shares	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Shares, Outstanding at Beginning of Year	213,899
Shares, Granted	277,261
Shares, Vested	(220,105)
Shares, Canceled	(13,472)
Shares, Outstanding at End of Year	257,583	213,899
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Roll Forward]
Shares, Outstanding at Beginning of Year, Weighted Average Grant Date Fair Value	$ 42.32
Shares, Granted, Weighted Average Grant Date Fair Value	49.34	$ 44.33	$ 42.28
Shares, Vested, Weighted Average Grant Date Fair Value	46.02
Shares, Canceled, Weighted Average Grant Date Fair Value	44.94
Shares, Outstanding at End of Year, Weighted Average Grant Date Fair Value	$ 46.58	$ 42.32
Shares, Outstanding at End of Year, Weighted Average Remaining Years Contractual Term	1 year 2 months 24 days
Shares, Outstanding at End of Year, Aggregate Intrinsic Value	$ 13,407,195

Stock Based Compensation (Perfo

Stock Based Compensation (Performance Units Information) (Details) - Performance Units [Member] - $ / shares	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted average period for recognizing unrecognized compensation cost	1 year 8 months 14 days
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Shares, Outstanding at Beginning of Year	332,461
Shares, Granted	378,800
Shares, Vested	(310,425)
Shares, Canceled	(23,295)
Shares, Outstanding at End of Year	377,541	332,461
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Roll Forward]
Shares, Outstanding at Beginning of Year, Weighted Average Grant Date Fair Value	$ 45.29
Shares, Granted, Weighted Average Grant Date Fair Value	54.95	$ 45.02	$ 45.97
Shares, Vested, Weighted Average Grant Date Fair Value	49.63
Shares, Cancelled, Weighted Average Grant Date Fair Value	48.57
Shares, Outstanding at End of Year, Weighted Average Grant Date Fair Value	$ 51.94	$ 45.29
Shares, Outstanding at End of Year, Weighted Average Remaining Years Contractual Term	1 year 8 months 14 days
Shares, Outstanding at End of Year, Aggregate Intrinsic Value	$ 19,651,009

Stock Based Compensation (Narra

Stock Based Compensation (Narrative) (Details) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Excess Tax Benefits	$ 3	$ 4	$ 4
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized	16,000,000
Percentage Of Fair Market Value Being Expected Purchase Price Of Employee Stock Purchase Plan	95.00%
Minimum Holding Period for Stock Purchased through Employee Stock Purchase Plan	3 months
Percentage Of Fair Market Value Being Expected Purchase Price Of Employee Stock Purchase Plan Non Represented	90.00%
Maximum Percentage Limit Of Base Pay For Employees For Purchasing Shares	10.00%
Shares issued under employee stock purchase plan	286,559	288,527	262,763
Shares issued under employee purchase plan, Average price per share	$ 47.44	$ 42.07	$ 40.70
Various [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant	13,000,000
Restricted Stock Units (RSUs) [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted average grant date fair value of granted shares	$ 49.34	$ 44.33	$ 42.28
Unrecognized compensation cost related to stock options expected to be recognized	$ 5
Weighted average period for recognizing unrecognized compensation cost	1 year 2 months 4 days
Total intrinsic value of restricted stock units vested	$ 12	$ 13	$ 17
Dividend equivalents accrued on stock units	26,987
Performance Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted average grant date fair value of granted shares	$ 54.95	$ 45.02	$ 45.97
Total intrinsic value of performance units vested	$ 17	$ 18	$ 17
Unrecognized compensation cost related to stock options expected to be recognized	$ 21
Weighted average period for recognizing unrecognized compensation cost	1 year 8 months 14 days
Dividend equivalents accrued on stock units	37,156
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights, Percentage	100.00%
Employee Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant	2,900,000
Minimum [Member] | Stock Options [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Expiration Period	1 year
Minimum [Member] | Restricted Stock Units (RSUs) [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Options vesting period	3 years
Minimum [Member] | Performance Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights, Percentage	0.00%
Maximum [Member] | Stock Options [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Options vesting period	4 years
Share-based Compensation Arrangement by Share-based Payment Award, Expiration Period	10 years
Maximum [Member] | Performance Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Options vesting period	3 years
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights, Percentage	200.00%

Other Income And Deductions (Sc

Other Income And Deductions (Schedule Of Other Income) (Detail) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Component of Other Income [Line Items]
Investment Income, Interest and Dividend		$ 52	$ 45	$ 43
Components of Other Income [Roll Forward]
Allowance for Funds Used During Construction		54	56	49
Solar Loan Interest		18	21	22
Donations		(17)	(28)	(2)
Other		(22)	(12)	(10)
Total Other Income and Deductions		85	82	102
PSE&G [Member]
Component of Other Income [Line Items]
Investment Income, Interest and Dividend		0	0	0
Components of Other Income [Roll Forward]
Allowance for Funds Used During Construction		54	56	49
Solar Loan Interest		18	21	22
Donations		0	(1)	(1)
Other		8	9	9
Total Other Income and Deductions		80	85	79
Power [Member]
Component of Other Income [Line Items]
Investment Income, Interest and Dividend		52	45	43
Components of Other Income [Roll Forward]
Allowance for Funds Used During Construction		0	0	0
Solar Loan Interest		0	0	0
Donations		0	(2)	(1)
Other		(31)	(23)	(19)
Total Other Income and Deductions		21	20	23
Other [Member]
Component of Other Income [Line Items]
Investment Income, Interest and Dividend	[1]	0	0	0
Components of Other Income [Roll Forward]
Allowance for Funds Used During Construction	[1]	0	0	0
Solar Loan Interest	[1]	0	0	0
Donations	[1]	(17)	(25)	0
Other	[1]	1	2	0
Total Other Income and Deductions	[1]	$ (16)	$ (23)	$ 0
[1]	Other consists of activity at PSEG (as parent company), Energy Holdings, Services, PSEG LI and intercompany eliminations.

Income Taxes (Reconciliation Of

Income Taxes (Reconciliation Of Reported Income Tax Expense) (Details) - USD ($) $ in Millions	3 Months Ended														6 Months Ended		12 Months Ended
	Dec. 31, 2018		Sep. 30, 2018	Jun. 30, 2018		Mar. 31, 2018		Dec. 31, 2017		Sep. 30, 2017	Jun. 30, 2017		Mar. 31, 2017		Jun. 30, 2018	[1]	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Income Taxes [Line Items]
Net Income	$ 199	[1]	$ 412			$ 558	[1]	$ 956	[1]	$ 395	$ 109	[1]	$ 114	[1]	$ 269
Net Income																	$ 1,438	$ 1,574	$ 887
Federal																	(97)	86	(74)
State																	83	(31)	61
Total Current																	(14)	55	(13)
Federal																	373	(482)	311
State																	71	92	28
Total Deferred																	444	(390)	339
Investment tax credit																	(13)	29	85
Total Income Tax																	417	(306)	411
Pre-Tax Income																	1,855	1,268	1,298
Tax Computed at Statutory Rate																	390	444	454
State Income Taxes (net of federal income tax)																	123	36	56
Uncertain Tax Positions																	(24)	(3)	(31)
Manufacturing Deduction																	0	(13)	(17)
Nuclear Decommissioning Trust																	(13)	19	3
Plant-Related Items																	(10)	(23)	(20)
Tax Credits																	(16)	(22)	(25)
Effective Income Tax Rate Reconciliation, Tax Settlement, Domestic, Amount																	0	6	0
Tax Adjustment Credit																	(30)	0	0
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, Amount																	3	(755)	0
Other																	(6)	5	(9)
Sub-Total																	27	(750)	(43)
Income Tax Provision																	$ 417	$ (306)	$ 411
Effective income tax rate																	22.50%	(24.10%)	31.70%
PSE&G [Member]
Income Taxes [Line Items]
Net Income	239		278	$ 231		319		220		246	208		299
Net Income																	$ 1,067	$ 973	$ 889
Federal																	(62)	(52)	(153)
State																	1	(1)	10
Total Current																	(61)	(53)	(143)
Federal																	287	492	551
State																	122	129	102
Total Deferred																	409	621	653
Investment tax credit																	(4)	(5)	5
Total Income Tax																	344	563	515
Pre-Tax Income																	1,411	1,536	1,404
Tax Computed at Statutory Rate																	296	538	491
State Income Taxes (net of federal income tax)																	98	83	72
Uncertain Tax Positions																	(1)	(9)	(18)
Plant-Related Items																	(10)	(23)	(20)
Tax Credits																	(8)	(9)	(7)
Tax Adjustment Credit																	(30)	0	0
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, Amount																	0	(10)	0
Other																	(1)	(7)	(3)
Sub-Total																	48	25	24
Income Tax Provision																	$ 344	$ 563	$ 515
Effective income tax rate																	24.40%	36.70%	36.70%
Power [Member]
Income Taxes [Line Items]
Net Income	$ (35)	[1]	$ 125	$ 41	[1]	$ 234	[1]	$ 610	[1]	$ 136	$ (97)	[1]	$ (170)	[1]
Net Income																	$ 365	$ 479	$ 18
Federal																	(164)	95	107
State																	24	(17)	40
Total Current																	(140)	78	147
Federal																	214	(804)	(222)
State																	1	(37)	(68)
Total Deferred																	215	(841)	(290)
Investment tax credit																	(9)	34	82
Total Income Tax																	66	(729)	(61)
Pre-Tax Income																	431	(250)	(43)
Tax Computed at Statutory Rate																	91	(88)	(15)
State Income Taxes (net of federal income tax)																	21	(36)	(18)
Uncertain Tax Positions																	(24)	7	9
Manufacturing Deduction																	0	(13)	(17)
Nuclear Decommissioning Trust																	(13)	19	3
Tax Credits																	(7)	(12)	(18)
Effective Income Tax Rate Reconciliation, Tax Settlement, Domestic, Amount																	0	1	0
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, Amount																	(1)	(610)	0
Other																	(1)	3	(5)
Sub-Total																	(25)	(641)	(46)
Income Tax Provision																	$ 66	$ (729)	$ (61)
Effective income tax rate																	15.30%	291.60%	141.90%
[1]	The increases in Operating Income at PSEG consolidated and Power in the first and second quarters of 2018 as compared to the same quarters in 2017 were primarily due to higher costs in 2017 related to closing the coal/gas Hudson and Mercer units, which were fully depreciated as of June 1, 2017. The increases in Operating Income at PSEG consolidated and Power in the fourth quarter 2018 as compared to the same quarter in 2017 were primarily due to lower MTM losses and a gain on the sale of the Hudson and Mercer units.The decreases in Net Income at PSEG consolidated and Power in the fourth quarter 2018 as compared to the same quarter in 2017 also reflected the impact of the one-time benefit recorded in December 2017 as a result of the remeasurement of deferred tax balances and the inclusion in 2018 of net unrealized losses on equity investments in the NDT Fund in accordance with new accounting guidance.

Income Taxes (Deferred Income T

Income Taxes (Deferred Income Tax) (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Income Taxes [Line Items]
Regulatory Liability Excess Deferred Tax	$ 606	$ 602
OPEB	163	217
Related to Uncertain Tax Positions	71	142
Total Noncurrent Assets	840	961
Plant-Related Items	4,817	4,257
New Jersey Corporate Business Tax	756	674
Leasing Activities	307	384
Pension Costs	111	123
AROs and NDT Fund	196	233
Taxes Recoverable Through Future Rate (net)	89	80
Deferred Tax Liabilities, Other	12	171
Total Non-Current Liabilities	6,288	5,922
Accumulated Deferred Investment Tax Credit	265	279
Net Total Noncurrent Deferred Income Taxes and ITC	5,713	5,240
Deferred Tax Liabilities, Net, Noncurrent	5,448	4,961
PSE&G [Member]
Income Taxes [Line Items]
Regulatory Liability Excess Deferred Tax	606	602
OPEB	114	116
Total Noncurrent Assets	720	718
Plant-Related Items	3,622	3,311
New Jersey Corporate Business Tax	486	378
Conservation Costs	36	24
Pension Costs	159	152
Taxes Recoverable Through Future Rate (net)	89	80
Deferred Tax Liabilities, Other	84	86
Total Non-Current Liabilities	4,476	4,031
Accumulated Deferred Investment Tax Credit	74	78
Net Total Noncurrent Deferred Income Taxes and ITC	3,830	3,391
Deferred Tax Liabilities, Net, Noncurrent	3,756	3,313
Power [Member]
Income Taxes [Line Items]
Contractual Liabilities & Environmental Costs	9	12
Related to Uncertain Tax Positions	60	45
Pension Costs	52	40
Other	98	93
Total Noncurrent Assets	219	190
Plant-Related Items	1,189	935
New Jersey Corporate Business Tax	260	225
AROs and NDT Fund	197	235
Total Non-Current Liabilities	1,646	1,395
Accumulated Deferred Investment Tax Credit	192	201
Net Total Noncurrent Deferred Income Taxes and ITC	1,619	1,406
Deferred Tax Liabilities, Net, Noncurrent	$ 1,427	$ 1,205

Income Taxes (Narrative) (Detai

Income Taxes (Narrative) (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Income Taxes [Line Items]
Non cash earnings benefit from new tax legislation		$ 745
Federal income tax rate	21.00%	35.00%
Provisional Deferred Tax Benefit	$ 3	$ (755)	$ 0
Bonus depreciation for tax purposes	50.00%
Current ITC rate for qualified property	30.00%
Regulatory Liabilities	$ 3,221	2,948
Revenue impact of additional excess deferred taxes	46
Deferred Tax Assets, interest disallowance	$ 54
NJ surcharge tax percent for 2018 to 2019	3.00%
NJ tax surcharge percent for 2020 to 2021	2.00%
NJ tax surcharge expense	$ 7
PSEG [Member]
Income Taxes [Line Items]
Federal income tax rate	21.00%
Energy Holdings [Member]
Income Taxes [Line Items]
Non cash earnings benefit from new tax legislation		147
Provisional Deferred Tax Benefit		(149)
PSE&G [Member]
Income Taxes [Line Items]
Provisional Deferred Tax Benefit	$ 0	(10)	0
Regulatory Liabilities	3,221	2,948
NOL Carryforwards	21
Power [Member]
Income Taxes [Line Items]
Non cash earnings benefit from new tax legislation		588
Provisional Deferred Tax Benefit	(1)	(610)	$ 0
Deferred Tax Assets, interest disallowance	8
NOL Carryforwards	14
Excess Deferred Income Taxes [Member] | PSE&G [Member]
Income Taxes [Line Items]
Reduction in Deferred Tax Liabilities		2,100
Regulatory Liabilities	3,170	$ 2,868
Additional Excess Deferred Taxes	$ 34

Income Taxes (Unrecognized Tax

Income Taxes (Unrecognized Tax Benefits) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Total Amount of Unrecognized Tax Benefits at January	$ 334	$ 328	$ 386
Increases as a Result of Positions Taken in a Prior Period	11	40	12
Decreases as a Result of Positions Taken in a Prior Period	(70)	(32)	(62)
Increases as a Result of Positions Taken during the Current Period	52	12	19
Decreases as a Result of Positions Taken during the Current Period	(3)	(1)	0
Decreases as a Result of Settlements with Taxing Authorities	(6)	0	0
Decreases due to Lapses of Applicable Statute of Limitations	0	(13)	(27)
Total Amount of Unrecognized Tax Benefits at December	318	334	328
Accumulated Deferred Income Taxes Associated with Unrecognized Tax Benefits	(173)	(157)	(200)
Regulatory Asset-Unrecognized Tax Benefits	(46)	(56)	(31)
Amount of unrecognized tax benefits that would affect the effective tax rate	99	121	97
Power [Member]
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Total Amount of Unrecognized Tax Benefits at January	142	128	111
Increases as a Result of Positions Taken in a Prior Period	4	18	6
Decreases as a Result of Positions Taken in a Prior Period	(37)	(10)	(1)
Increases as a Result of Positions Taken during the Current Period	48	6	12
Decreases as a Result of Positions Taken during the Current Period	0	0	0
Decreases as a Result of Settlements with Taxing Authorities	(6)	0	0
Decreases due to Lapses of Applicable Statute of Limitations	0	0	0
Total Amount of Unrecognized Tax Benefits at December	151	142	128
Accumulated Deferred Income Taxes Associated with Unrecognized Tax Benefits	(104)	(72)	(74)
Regulatory Asset-Unrecognized Tax Benefits	0	0	0
Amount of unrecognized tax benefits that would affect the effective tax rate	47	70	54
PSE&G [Member]
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Total Amount of Unrecognized Tax Benefits at January	135	140	181
Increases as a Result of Positions Taken in a Prior Period	4	15	3
Decreases as a Result of Positions Taken in a Prior Period	(31)	(11)	(23)
Increases as a Result of Positions Taken during the Current Period	3	5	6
Decreases as a Result of Positions Taken during the Current Period	(3)	(1)	0
Decreases as a Result of Settlements with Taxing Authorities	0	0	0
Decreases due to Lapses of Applicable Statute of Limitations	0	(13)	(27)
Total Amount of Unrecognized Tax Benefits at December	108	135	140
Accumulated Deferred Income Taxes Associated with Unrecognized Tax Benefits	(57)	(73)	(106)
Regulatory Asset-Unrecognized Tax Benefits	(46)	(56)	(31)
Amount of unrecognized tax benefits that would affect the effective tax rate	5	6	3
Energy Holdings [Member]
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Total Amount of Unrecognized Tax Benefits at January	53	57	93
Increases as a Result of Positions Taken in a Prior Period	3	8	2
Decreases as a Result of Positions Taken in a Prior Period	(2)	(13)	(38)
Increases as a Result of Positions Taken during the Current Period	0	1	0
Decreases as a Result of Positions Taken during the Current Period	0	0	0
Decreases as a Result of Settlements with Taxing Authorities	0	0	0
Decreases due to Lapses of Applicable Statute of Limitations	0	0	0
Total Amount of Unrecognized Tax Benefits at December	54	53	57
Accumulated Deferred Income Taxes Associated with Unrecognized Tax Benefits	(12)	(12)	(20)
Regulatory Asset-Unrecognized Tax Benefits	0	0	0
Amount of unrecognized tax benefits that would affect the effective tax rate	$ 42	$ 41	$ 37

Income Taxes (Interest And Pena

Income Taxes (Interest And Penalties Related To Unrecognized Tax Benefits) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Income Taxes [Line Items]
Accumulated Interest and Penalties on Uncertain Tax Positions	$ 43	$ 70	$ 59
PSE&G [Member]
Income Taxes [Line Items]
Accumulated Interest and Penalties on Uncertain Tax Positions	12	25	22
Power [Member]
Income Taxes [Line Items]
Accumulated Interest and Penalties on Uncertain Tax Positions	9	24	17
Energy Holdings [Member]
Income Taxes [Line Items]
Accumulated Interest and Penalties on Uncertain Tax Positions	$ 22	$ 21	$ 20

Income Taxes (Possible Decrease

Income Taxes (Possible Decrease In Total Unrecognized Tax Benefits Including Interest) (Details) $ in Millions	Dec. 31, 2018USD ($)
Income Taxes [Line Items]
Possible Decrease in Total Unrecognized Tax Benefits including Interest in next twelve months	$ 112
PSE&G [Member]
Income Taxes [Line Items]
Possible Decrease in Total Unrecognized Tax Benefits including Interest in next twelve months	62
Power [Member]
Income Taxes [Line Items]
Possible Decrease in Total Unrecognized Tax Benefits including Interest in next twelve months	$ 34

Income Taxes (Description Of In

Income Taxes (Description Of Income Tax Years By Material Jurisdictions) (Details)	12 Months Ended
	Dec. 31, 2018
Federal [Member] | PSEG [Member]
Income Taxes [Line Items]
Income Tax Year Subject to Examination by Material Jurisdictions	2011-2017
Federal [Member] | Power [Member]
Income Taxes [Line Items]
Income Tax Year Subject to Examination by Material Jurisdictions	N/A
Federal [Member] | PSE&G [Member]
Income Taxes [Line Items]
Income Tax Year Subject to Examination by Material Jurisdictions	N/A
New Jersey [Member] | PSEG [Member]
Income Taxes [Line Items]
Income Tax Year Subject to Examination by Material Jurisdictions	2006-2017
New Jersey [Member] | Power [Member]
Income Taxes [Line Items]
Income Tax Year Subject to Examination by Material Jurisdictions	N/A
New Jersey [Member] | PSE&G [Member]
Income Taxes [Line Items]
Income Tax Year Subject to Examination by Material Jurisdictions	2011-2017
Pennsylvania [Member] | PSEG [Member]
Income Taxes [Line Items]
Income Tax Year Subject to Examination by Material Jurisdictions	2015-2017
Pennsylvania [Member] | Power [Member]
Income Taxes [Line Items]
Income Tax Year Subject to Examination by Material Jurisdictions	N/A
Pennsylvania [Member] | PSE&G [Member]
Income Taxes [Line Items]
Income Tax Year Subject to Examination by Material Jurisdictions	2015-2017
Connecticut [Member] | PSEG [Member]
Income Taxes [Line Items]
Income Tax Year Subject to Examination by Material Jurisdictions	2016-2017
Connecticut [Member] | Power [Member]
Income Taxes [Line Items]
Income Tax Year Subject to Examination by Material Jurisdictions	N/A
Connecticut [Member] | PSE&G [Member]
Income Taxes [Line Items]
Income Tax Year Subject to Examination by Material Jurisdictions	N/A
California [Member] | PSEG [Member]
Income Taxes [Line Items]
Income Tax Year Subject to Examination by Material Jurisdictions	2006-2017
California [Member] | Power [Member]
Income Taxes [Line Items]
Income Tax Year Subject to Examination by Material Jurisdictions	N/A
California [Member] | PSE&G [Member]
Income Taxes [Line Items]
Income Tax Year Subject to Examination by Material Jurisdictions	N/A
New York [Member] | PSEG [Member]
Income Taxes [Line Items]
Income Tax Year Subject to Examination by Material Jurisdictions	2,017
New York [Member] | Power [Member]
Income Taxes [Line Items]
Income Tax Year Subject to Examination by Material Jurisdictions	2,017
New York [Member] | PSE&G [Member]
Income Taxes [Line Items]
Income Tax Year Subject to Examination by Material Jurisdictions	N/A

Accumulated Other Comprehensi_3

Accumulated Other Comprehensive Income (Loss), Net of Tax Accumulated Other Comprehensive Income (Loss), Net of Tax (Changes in AOCI) (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Jun. 30, 2018	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Jan. 01, 2018
Accumulated Other Comprehensive Income (Loss) [Line Items]
Cumulative Effect of New Accounting Principle in Period of Adoption			$ 0		$ (176)
Beginning Balance		$ (229)	(263)	$ (295)
Other Comprehensive Income before Reclassifications		(9)	77	(3)
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)		37	(43)	35
Net Current Period Other Comprehensive Income (Loss)		28	34	32
Ending Balance		(377)	(229)	(263)
Net Change in Accumulated Other Comprehensive Income		(148)
Power [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Cumulative Effect of New Accounting Principle in Period of Adoption			0		(175)
Beginning Balance		(172)	(211)	(240)
Other Comprehensive Income before Reclassifications		(3)	78	(3)
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)		31	(39)	32
Net Current Period Other Comprehensive Income (Loss)		28	39	29
Ending Balance		(319)	(172)	(211)
Net Change in Accumulated Other Comprehensive Income		(147)
Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Cumulative Effect of New Accounting Principle in Period of Adoption					0
Beginning Balance		0	2	0
Other Comprehensive Income before Reclassifications	$ (1)	(1)	0	2
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)		0	(2)	0
Net Current Period Other Comprehensive Income (Loss)		(1)	(2)	2
Ending Balance		(1)	0	2
Net Change in Accumulated Other Comprehensive Income		(1)
Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | Power [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Cumulative Effect of New Accounting Principle in Period of Adoption					0
Beginning Balance		0	0	0
Other Comprehensive Income before Reclassifications		0	0	0
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)		0	0	0
Net Current Period Other Comprehensive Income (Loss)		0	0	0
Ending Balance		0	0	0
Net Change in Accumulated Other Comprehensive Income		0
Accumulated Defined Benefit Plans Adjustment [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Cumulative Effect of New Accounting Principle in Period of Adoption					0
Beginning Balance		(406)	(398)	(386)
Other Comprehensive Income before Reclassifications		17	(32)	(45)
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)		29	24	33
Net Current Period Other Comprehensive Income (Loss)		46	(8)	(12)
Ending Balance		(360)	(406)	(398)
Net Change in Accumulated Other Comprehensive Income		46
Accumulated Defined Benefit Plans Adjustment [Member] | Power [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Cumulative Effect of New Accounting Principle in Period of Adoption					0
Beginning Balance		(347)	(340)	(327)
Other Comprehensive Income before Reclassifications		16	(28)	(42)
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)		25	21	29
Net Current Period Other Comprehensive Income (Loss)		41	(7)	(13)
Ending Balance		(306)	(347)	(340)
Net Change in Accumulated Other Comprehensive Income		41
Accumulated Net Unrealized Investment Gain (Loss) [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Cumulative Effect of New Accounting Principle in Period of Adoption					(176)
Beginning Balance		177	133	91
Other Comprehensive Income before Reclassifications		(25)	109	40
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)		8	(65)	2
Net Current Period Other Comprehensive Income (Loss)		(17)	44	42
Ending Balance		(16)	177	133
Net Change in Accumulated Other Comprehensive Income		(193)
Accumulated Net Unrealized Investment Gain (Loss) [Member] | Power [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Cumulative Effect of New Accounting Principle in Period of Adoption					$ (175)
Beginning Balance		175	129	87
Other Comprehensive Income before Reclassifications		(19)	106	39
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)		6	(60)	3
Net Current Period Other Comprehensive Income (Loss)		(13)	46	42
Ending Balance		(13)	$ 175	$ 129
Net Change in Accumulated Other Comprehensive Income		$ (188)

Accumulated Other Comprehensi_4

Accumulated Other Comprehensive Income (Loss), Net of Tax Accumulated Other Comprehensive Income (Loss), Net of Tax (Reclassifications out of AOCI) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Accumulated Other Comprehensive Income (Loss) [Line Items]
Amount Reclassified from Accumulated Other Comprehensive Income, Pre-Tax	$ (54)	$ 96	$ (62)
Amount Reclassified from Accumulated Other Comprehensive Income, Tax	17	(53)	27
Amount Reclassified from Accumulated Other Comprehensive Income, After-Tax	(37)	43	(35)
Accumulated Net Unrealized Investment Gain (Loss) [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Amount Reclassified from AOCI for Available for Sale Securities, Pre-Tax	(13)	134	(6)
Amount Reclassified from AOCI for Available for Sale Securities, Tax	5	(69)	4
Amount Reclassified from AOCI for Available for Sale Securities, After-Tax	8	(65)	2
Amount Reclassified from Accumulated Other Comprehensive Income, After-Tax	(8)	65	(2)
Accumulated Defined Benefit Plans Adjustment [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Amount Reclassified from AOCI for Pension and OPEB Plans, Pre-Tax	(41)	(41)	(56)
Amount Reclassified from AOCI for Pension and OPEB Plans, Tax	12	17	23
Amount Reclassified from AOCI for Pension and OPEB Plans, After-Tax	(29)	(24)	(33)
Amount Reclassified from Accumulated Other Comprehensive Income, After-Tax	(29)	(24)	(33)
Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Amount Reclassified from AOCI for Cash Flow Hedges, Pre-Tax	0	3
Amount Reclassified from AOCI for Cash Flow Hedges, Tax		(1)
Amount Reclassified from AOCI for Cash Flow Hedges, After-Tax		2
Amount Reclassified from Accumulated Other Comprehensive Income, After-Tax	0	2	0
Net Gains (Losses) on Trust Investments [Member] | Accumulated Net Unrealized Investment Gain (Loss) [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Amount Reclassified from AOCI for Available for Sale Securities, Pre-Tax	(13)	134	(6)
Amount Reclassified from AOCI for Available for Sale Securities, Tax	5	(69)	(4)
Amount Reclassified from AOCI for Available for Sale Securities, After-Tax	(8)	65	(2)
Interest Expense [Member] | Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Amount Reclassified from AOCI for Cash Flow Hedges, Pre-Tax		3
Amount Reclassified from AOCI for Cash Flow Hedges, Tax		1
Amount Reclassified from AOCI for Cash Flow Hedges, After-Tax		2
Non-Operating Pension and OPEB Credits (Costs) [Member] | Accumulated Defined Benefit Plans Adjustment [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Amortization of Prior Service (Cost) Credit, Pre-Tax	6	10	(12)
Amortization of Prior Service (Cost) Credit, Tax	(2)	(4)	(5)
Amortization of Prior Service (Cost) Credit, After-Tax	4	6	7
Amortization of Actuarial Loss, Pre-Tax	(47)	(51)	68
Amortization of Actuarial Loss, Tax	(14)	(21)	(28)
Amortization of Actuarial Loss, After-Tax	(33)	(30)	(40)
Power [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Amount Reclassified from Accumulated Other Comprehensive Income, Pre-Tax	(46)	90	(54)
Amount Reclassified from Accumulated Other Comprehensive Income, Tax	15	(51)	22
Amount Reclassified from Accumulated Other Comprehensive Income, After-Tax	(31)	39	(32)
Power [Member] | Accumulated Net Unrealized Investment Gain (Loss) [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Amount Reclassified from AOCI for Available for Sale Securities, Pre-Tax	(11)	125	(6)
Amount Reclassified from AOCI for Available for Sale Securities, Tax	5	(65)	3
Amount Reclassified from AOCI for Available for Sale Securities, After-Tax	6	(60)	3
Amount Reclassified from Accumulated Other Comprehensive Income, After-Tax	(6)	60	(3)
Power [Member] | Accumulated Defined Benefit Plans Adjustment [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Amount Reclassified from AOCI for Pension and OPEB Plans, Pre-Tax	(35)	(35)	(48)
Amount Reclassified from AOCI for Pension and OPEB Plans, Tax	10	14	19
Amount Reclassified from AOCI for Pension and OPEB Plans, After-Tax	(25)	(21)	(29)
Amount Reclassified from Accumulated Other Comprehensive Income, After-Tax	(25)	(21)	(29)
Power [Member] | Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Amount Reclassified from Accumulated Other Comprehensive Income, After-Tax	0	0	0
Power [Member] | Net Gains (Losses) on Trust Investments [Member] | Accumulated Net Unrealized Investment Gain (Loss) [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Amount Reclassified from AOCI for Available for Sale Securities, Pre-Tax	(11)	125	(6)
Amount Reclassified from AOCI for Available for Sale Securities, Tax	5	(65)	(3)
Amount Reclassified from AOCI for Available for Sale Securities, After-Tax	(6)	60	(3)
Power [Member] | Non-Operating Pension and OPEB Credits (Costs) [Member] | Accumulated Defined Benefit Plans Adjustment [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Amortization of Prior Service (Cost) Credit, Pre-Tax	5	9	(11)
Amortization of Prior Service (Cost) Credit, Tax	(1)	(4)	(5)
Amortization of Prior Service (Cost) Credit, After-Tax	4	5	6
Amortization of Actuarial Loss, Pre-Tax	(40)	(44)	59
Amortization of Actuarial Loss, Tax	(11)	(18)	(24)
Amortization of Actuarial Loss, After-Tax	$ (29)	$ (26)	$ (35)

Earnings Per Share (EPS) And _3

Earnings Per Share (EPS) And Dividends (Basic And Diluted Earnings Per Share Computation) (Detail) - USD ($) $ / shares in Units, shares in Thousands, $ in Millions	3 Months Ended												6 Months Ended		12 Months Ended
	Dec. 31, 2018		Sep. 30, 2018	Mar. 31, 2018		Dec. 31, 2017		Sep. 30, 2017	Jun. 30, 2017		Mar. 31, 2017		Jun. 30, 2018		Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Earnings Per Share, Diluted [Line Items]
Net Income															$ 1,438	$ 1,574	$ 887
Effect of Stock Based Compensation Awards, Basic															0	0	0
Total Shares, Basic	504,000		504,000	504,000		505,000		505,000	505,000		505,000		504,000		504,000	505,000	505,000
Effect of Stock Based Compensation Awards, Diluted															3,000	2,000	3,000
Total Shares, Diluted	508,000		507,000	507,000		508,000		507,000	507,000		508,000		507,000		507,000	507,000	508,000
Weighted Average Common Shares Outstanding Before Various Effects Basic															504,000	505,000	505,000
Weighted Average Common Shares Outstanding Before Various Effects Diluted															504,000	505,000	505,000
Earnings Per Share, Basic	$ 0.39	[1]	$ 0.82	$ 1.11	[1]	$ 1.89	[1]	$ 0.78	$ 0.22	[1]	$ 0.23	[1]	$ 0.53	[1]	$ 2.85	$ 3.12	$ 1.76
Earnings Per Share, Diluted	$ 0.39	[1]	$ 0.81	$ 1.10	[1]	$ 1.88	[1]	$ 0.78	$ 0.22	[1]	$ 0.22	[1]	$ 0.53	[1]	$ 2.83	$ 3.10	$ 1.75
Stock Options Excluded from Weighted Average Common Shares used for diluted EPS																	400
[1]	The increases in Operating Income at PSEG consolidated and Power in the first and second quarters of 2018 as compared to the same quarters in 2017 were primarily due to higher costs in 2017 related to closing the coal/gas Hudson and Mercer units, which were fully depreciated as of June 1, 2017. The increases in Operating Income at PSEG consolidated and Power in the fourth quarter 2018 as compared to the same quarter in 2017 were primarily due to lower MTM losses and a gain on the sale of the Hudson and Mercer units.The decreases in Net Income at PSEG consolidated and Power in the fourth quarter 2018 as compared to the same quarter in 2017 also reflected the impact of the one-time benefit recorded in December 2017 as a result of the remeasurement of deferred tax balances and the inclusion in 2018 of net unrealized losses on equity investments in the NDT Fund in accordance with new accounting guidance.

Earnings Per Share (EPS) And _4

Earnings Per Share (EPS) And Dividends (Dividend Payments On Common Stock) (Detail) - USD ($) $ / shares in Units, $ in Millions	1 Months Ended	12 Months Ended
	Feb. 28, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Earnings Per Share, Diluted [Line Items]
Dividend Payments on Common Stock, Per Share		$ 1.80	$ 1.72	$ 1.64
Dividend Payments on Common Stock		$ 910	$ 870	$ 830
Subsequent Event [Member]
Earnings Per Share, Diluted [Line Items]
Common stock dividends per share	$ 0.47

Financial Information By Busi_3

Financial Information By Business Segments (Financial Information By Business Segments) (Detail) - USD ($) $ in Millions		3 Months Ended												6 Months Ended		12 Months Ended
		Dec. 31, 2018		Sep. 30, 2018	Mar. 31, 2018		Dec. 31, 2017		Sep. 30, 2017	Jun. 30, 2017		Mar. 31, 2017		Jun. 30, 2018		Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Segment Reporting Information [Line Items]
Operating Revenues		$ 2,468		$ 2,394	$ 2,818		$ 2,107		$ 2,254	$ 2,142		$ 2,591		$ 2,016		$ 9,696	$ 9,094	$ 8,966
Depreciation and Amortization																1,158	1,986	1,476
Operating Income (Loss)		501	[1]	$ 554	$ 832	[1]	363	[1]	$ 693	$ 195	[1]	$ 178	[1]	$ 411	[1]	2,298	1,429	1,598
Income from Equity Method Investments																15	14	11
Interest Income																29	30	30
Interest Expense																(476)	(391)	(385)
Income (Loss) before Income Taxes																1,855	1,268	1,298
Income Tax Expense (Benefit)																417	(306)	411
Net Income (Loss)																1,438	1,574	887
Gross Additions to Long-Lived Assets																3,912	4,190	4,199
Total Assets		45,326					42,716									45,326	42,716	40,070
Investments in Equity Method Subsidiaries		86					87									86	87	102
Power [Member]
Segment Reporting Information [Line Items]
Operating Revenues																4,146	3,860	3,861
PSE&G [Member]
Segment Reporting Information [Line Items]
Operating Revenues																6,471	6,324	6,303
Other [Member]
Segment Reporting Information [Line Items]
Operating Revenues																571	466	370
Eliminations [Member]
Segment Reporting Information [Line Items]
Operating Revenues																(1,492)	(1,556)	(1,568)
Retained Earnings [Member]
Segment Reporting Information [Line Items]
Net Income (Loss)																1,438	1,574	887
Operating Segments [Member] | Power [Member]
Segment Reporting Information [Line Items]
Operating Revenues																4,146	3,860	3,861
Depreciation and Amortization																354	1,268	881
Operating Income (Loss)																596	(367)	17
Income from Equity Method Investments																15	14	11
Interest Income																5	3	4
Interest Expense																(76)	(50)	(84)
Income (Loss) before Income Taxes																431	(250)	(43)
Income Tax Expense (Benefit)																66	(729)	(61)
Net Income (Loss)																365	479	18
Gross Additions to Long-Lived Assets																996	1,231	1,343
Total Assets		12,594					12,418									12,594	12,418	12,193
Investments in Equity Method Subsidiaries		86					87									86	87	102
Operating Segments [Member] | PSE&G [Member]
Segment Reporting Information [Line Items]
Operating Revenues																6,471	6,324	6,303
Depreciation and Amortization																770	685	565
Operating Income (Loss)																1,606	1,760	1,629
Income from Equity Method Investments																0	0	0
Interest Income																21	24	24
Interest Expense																(333)	(303)	(289)
Income (Loss) before Income Taxes																1,411	1,536	1,404
Income Tax Expense (Benefit)																344	563	515
Net Income (Loss)																1,067	973	889
Gross Additions to Long-Lived Assets																2,896	2,919	2,816
Total Assets		31,109					28,554									31,109	28,554	26,288
Investments in Equity Method Subsidiaries		0					0									0	0	0
Operating Segments [Member] | Other [Member]
Segment Reporting Information [Line Items]
Operating Revenues	[2]															571	466	370
Depreciation and Amortization	[2]															34	33	30
Operating Income (Loss)	[2]															96	36	(48)
Income from Equity Method Investments	[2]															0	0	0
Interest Income	[2]															9	5	4
Interest Expense	[2]															(73)	(40)	(14)
Income (Loss) before Income Taxes	[2]															13	(18)	(63)
Income Tax Expense (Benefit)	[2]															7	(140)	(43)
Net Income (Loss)	[2]															6	122	(20)
Gross Additions to Long-Lived Assets	[2]															20	40	40
Total Assets	[2]	2,604					2,666									2,604	2,666	2,373
Investments in Equity Method Subsidiaries	[2]	0					0									0	0	0
Eliminations [Member]
Segment Reporting Information [Line Items]
Operating Revenues	[3]															(1,492)	(1,556)	(1,568)
Depreciation and Amortization	[3]															0	0	0
Operating Income (Loss)	[3]															0	0	0
Income from Equity Method Investments	[3]															0	0	0
Interest Income	[3]															(6)	(2)	(2)
Interest Expense	[3]															6	2	2
Income (Loss) before Income Taxes	[3]															0	0	0
Income Tax Expense (Benefit)	[3]															0	0	0
Net Income (Loss)	[3]															0		0
Gross Additions to Long-Lived Assets	[3]															0	0	0
Total Assets	[3]	(981)					(922)									(981)	(922)	(784)
Investments in Equity Method Subsidiaries	[3]	$ 0					$ 0									$ 0	$ 0	$ 0
[1]	The increases in Operating Income at PSEG consolidated and Power in the first and second quarters of 2018 as compared to the same quarters in 2017 were primarily due to higher costs in 2017 related to closing the coal/gas Hudson and Mercer units, which were fully depreciated as of June 1, 2017. The increases in Operating Income at PSEG consolidated and Power in the fourth quarter 2018 as compared to the same quarter in 2017 were primarily due to lower MTM losses and a gain on the sale of the Hudson and Mercer units.The decreases in Net Income at PSEG consolidated and Power in the fourth quarter 2018 as compared to the same quarter in 2017 also reflected the impact of the one-time benefit recorded in December 2017 as a result of the remeasurement of deferred tax balances and the inclusion in 2018 of net unrealized losses on equity investments in the NDT Fund in accordance with new accounting guidance.
[2]	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.
[3]	Intercompany eliminations primarily relate to intercompany transactions between PSE&G and Power. For a further discussion of the intercompany transactions between PSE&G and Power, see Note 25. Related-Party Transactions.

Related-Party Transactions (Sch

Related-Party Transactions (Schedule Of Related Party Transactions, Revenue) (Detail) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
PSE&G [Member]
Related Party Transaction [Line Items]
Billings from Power through BGSS and BGS	[1]	$ 1,514	$ 1,580	$ 1,587
Administrative Billings from Services	[2]	333	331	312
Total Expense Billings from Affiliates		1,847	1,911	1,899
Power [Member]
Related Party Transaction [Line Items]
Administrative Billings from Services	[2]	$ 145	$ 168	$ 179
[1]	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.
[2]	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.

Related-Party Transactions (S_2

Related-Party Transactions (Schedule Of Related Party Transactions, Receivables) (Detail) - Power [Member] - USD ($) $ in Millions		Dec. 31, 2018	Dec. 31, 2017
Related Party Transaction [Line Items]
Receivable from PSE&G through BGS and BGSS Contracts	[1]	$ 245	$ 221
Receivable from (Payable to) Services	[2]	(16)	(28)
Payable to PSEG	[3]	0	29
Accounts Payable-Affiliated Companies		(16)	(57)
Short Term Loan from Affiliate	[4]	193	281
Receivable from PSEG	[3]	29	0
Accounts Receivable-Affilated Companies, net		274	221
Working Capital Advances to Services	[5]	17	17
Accounts Payable, Related Parties, Noncurrent		$ 76	$ 52
[1]	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.
[2]	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.
[3]	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.
[4]	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.
[5]	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 Consolidated Balance Sheets.

Related-Party Transactions Rela

Related-Party Transactions Related-Party Revenues and Expenses (Details) - Power [Member] - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Related Party Transaction [Line Items]
Billings To PSE&G through BGSS and BGS	[1]	$ 1,514	$ 1,580	$ 1,587
Administrative Billings from Services	[2]	$ 145	$ 168	$ 179
[1]	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.
[2]	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.

Related-Party Transactions (S_3

Related-Party Transactions (Schedule Of Related Party Transactions, Payables) (Detail) - PSE&G [Member] - USD ($) $ in Millions		Dec. 31, 2018	Dec. 31, 2017
Related Party Transaction [Line Items]
Payable to Power through BGS and BGSS Contracts	[1]	$ (245)	$ (221)
Receivable from (Payable to) Services	[2]	(76)	(78)
Payable to PSEG	[3]	0	41
Receivable from PSEG	[3]	123	0
Accounts Payable-Affiliated Companies		321	340
Working Capital Advances to Services	[4]	33	33
Long-Term Accrued Taxes Receivable (Payable)		$ (69)	$ (91)
[1]	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.
[2]	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.
[3]	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.
[4]	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 Consolidated Balance Sheets.

Selected Quarterly Data (Schedu

Selected Quarterly Data (Schedule Of Selected Quarterly Data) (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	3 Months Ended														6 Months Ended		12 Months Ended
	Dec. 31, 2018		Sep. 30, 2018	Jun. 30, 2018		Mar. 31, 2018		Dec. 31, 2017		Sep. 30, 2017	Jun. 30, 2017		Mar. 31, 2017		Jun. 30, 2018		Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Schedule of Quarterly Data [Line Items]
Operating Revenues	$ 2,468		$ 2,394			$ 2,818		$ 2,107		$ 2,254	$ 2,142		$ 2,591		$ 2,016		$ 9,696	$ 9,094	$ 8,966
Operating Income (Loss)	501	[1]	554			832	[1]	363	[1]	693	195	[1]	178	[1]	411	[1]	2,298	1,429	1,598
Net Income (Loss)	$ 199	[1]	$ 412			$ 558	[1]	$ 956	[1]	$ 395	$ 109	[1]	$ 114	[1]	$ 269	[1]
Net Income (Loss)																	$ 1,438	$ 1,574	$ 887
Basic	504		504			504		505		505	505		505		504		504	505	505
Diluted	508		507			507		508		507	507		508		507		507	507	508
Earnings Per Share, Basic	$ 0.39	[1]	$ 0.82			$ 1.11	[1]	$ 1.89	[1]	$ 0.78	$ 0.22	[1]	$ 0.23	[1]	$ 0.53	[1]	$ 2.85	$ 3.12	$ 1.76
Earnings Per Share, Diluted	$ 0.39	[1]	$ 0.81			$ 1.10	[1]	$ 1.88	[1]	$ 0.78	$ 0.22	[1]	$ 0.22	[1]	$ 0.53	[1]	$ 2.83	$ 3.10	$ 1.75
PSE&G [Member]
Schedule of Quarterly Data [Line Items]
Operating Revenues	$ 1,645		$ 1,595	$ 1,386		$ 1,845		$ 1,575		$ 1,530	$ 1,393		$ 1,826				$ 6,471	$ 6,324	$ 6,303
Operating Income (Loss)	345		421	358		482		396		461	380		523				1,606	1,760	1,629
Net Income (Loss)	239		278	231		319		220		246	208		299
Net Income (Loss)																	1,067	973	889
Power [Member]
Schedule of Quarterly Data [Line Items]
Operating Revenues	1,108		868	767		1,403		827		846	918		1,269				4,146	3,860	3,861
Operating Income (Loss)	113	[1]	112	42	[1]	329	[1]	(84)	[1]	211	(189)	[1]	(305)	[1]			596	(367)	17
Net Income (Loss)	$ (35)	[1]	$ 125	$ 41	[1]	$ 234	[1]	$ 610	[1]	$ 136	$ (97)	[1]	$ (170)	[1]
Net Income (Loss)																	$ 365	$ 479	$ 18
[1]	The increases in Operating Income at PSEG consolidated and Power in the first and second quarters of 2018 as compared to the same quarters in 2017 were primarily due to higher costs in 2017 related to closing the coal/gas Hudson and Mercer units, which were fully depreciated as of June 1, 2017. The increases in Operating Income at PSEG consolidated and Power in the fourth quarter 2018 as compared to the same quarter in 2017 were primarily due to lower MTM losses and a gain on the sale of the Hudson and Mercer units.The decreases in Net Income at PSEG consolidated and Power in the fourth quarter 2018 as compared to the same quarter in 2017 also reflected the impact of the one-time benefit recorded in December 2017 as a result of the remeasurement of deferred tax balances and the inclusion in 2018 of net unrealized losses on equity investments in the NDT Fund in accordance with new accounting guidance.

Guarantees Of Debt (Schedule Of

Guarantees Of Debt (Schedule Of Financial Statements Of Guarantors) (Detail) - USD ($) $ in Millions	3 Months Ended														6 Months Ended		12 Months Ended
	Dec. 31, 2018		Sep. 30, 2018	Jun. 30, 2018		Mar. 31, 2018		Dec. 31, 2017		Sep. 30, 2017	Jun. 30, 2017		Mar. 31, 2017		Jun. 30, 2018		Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Guarantees of Debt [Line Items]
Operating Revenues	$ 2,468		$ 2,394			$ 2,818		$ 2,107		$ 2,254	$ 2,142		$ 2,591		$ 2,016		$ 9,696	$ 9,094	$ 8,966
Operating Expenses																	7,398	7,665	7,368
Operating Income (Loss)	501	[1]	554			832	[1]	363	[1]	693	195	[1]	178	[1]	$ 411	[1]	2,298	1,429	1,598
Equity Earnings (Losses) of Subsidiaries																	15	14	11
Net Gains (Losses) on Trust Investments																	(143)	134	(6)
Other Income (Deductions)																	85	82	102
Non-Operating Pension and Other Postretirement Plan Credits (Costs)																	76	0	(22)
Interest Expense																	(476)	(391)	(385)
Income Tax Benefit (Expense)																	(417)	306	(411)
Net Income																	1,438	1,574	887
Net Cash Provided By (Used In) Operating Activities																	2,913	3,260	3,313
Net Cash Provided By (Used In) Investing Activities																	(3,916)	(4,256)	(4,248)
Net Cash Provided By (Used In) Financing Activities																	887	885	966
Current Assets	3,507							3,312									3,507	3,312
Property, Plant and Equipment, net	34,363							31,797									34,363	31,797
Noncurrent Assets	7,456							7,607									7,456	7,607
Total Assets	45,326							42,716									45,326	42,716	40,070
Current Liabilities	4,935							4,168									4,935	4,168
Noncurrent Liabilities	12,846							12,633									12,846	12,633
Total Long-Term Debt	13,168							12,068									13,168	12,068
Member's Equity	14,377							13,847									14,377	13,847	13,130	$ 13,067
TOTAL LIABILITIES AND CAPITALIZATION	45,326							42,716									45,326	42,716
Power [Member]
Guarantees of Debt [Line Items]
Operating Revenues	1,108		868	$ 767		1,403		827		846	918		1,269				4,146	3,860	3,861
Operating Expenses																	3,550	4,227	3,844
Operating Income (Loss)	113	[1]	$ 112	$ 42	[1]	$ 329	[1]	(84)	[1]	$ 211	$ (189)	[1]	$ (305)	[1]			596	(367)	17
Equity Earnings (Losses) of Subsidiaries																	15	14	11
Net Gains (Losses) on Trust Investments																	(140)	125	(6)
Other Income (Deductions)																	21	20	23
Non-Operating Pension and Other Postretirement Plan Credits (Costs)																	15	8	(4)
Interest Expense																	(76)	(50)	(84)
Income Tax Benefit (Expense)																	(66)	729	61
Net Income																	365	479	18
Net Cash Provided By (Used In) Operating Activities																	1,084	1,326	1,255
Net Cash Provided By (Used In) Investing Activities																	(1,051)	(1,232)	(1,147)
Net Cash Provided By (Used In) Financing Activities																	(43)	(73)	(109)
Current Assets	1,507							1,341									1,507	1,341
Property, Plant and Equipment, net	8,842							8,596									8,842	8,596
Noncurrent Assets	2,245							2,481									2,245	2,481
Total Assets	12,594							12,418									12,594	12,418
Current Liabilities	842							1,435									842	1,435
Noncurrent Liabilities	3,001							2,880									3,001	2,880
Total Long-Term Debt	2,791							2,136									2,791	2,136
Member's Equity	5,960							5,967									5,960	5,967	5,799	$ 6,002
TOTAL LIABILITIES AND CAPITALIZATION	12,594							12,418									12,594	12,418
Power Senior Notes [Member]
Guarantees of Debt [Line Items]
Operating Revenues																	4,146	3,860	3,861
Operating Expenses																	3,550	4,227	3,844
Operating Income (Loss)																	596	(367)	17
Equity Earnings (Losses) of Subsidiaries																	15	14	11
Net Gains (Losses) on Trust Investments																	(140)	125	(6)
Other Income (Deductions)																	21	20	23
Non-Operating Pension and Other Postretirement Plan Credits (Costs)																	15	8	(4)
Interest Expense																	(76)	(50)	(84)
Income Tax Benefit (Expense)																	(66)	729	61
Net Income																	365	479	18
Comprehensive Income (Loss), Net of Tax, Attributable to Parent																	393	518	47
Net Cash Provided By (Used In) Operating Activities																	1,084	1,326	1,255
Net Cash Provided By (Used In) Investing Activities																	(1,051)	(1,232)	(1,147)
Net Cash Provided By (Used In) Financing Activities																	(43)	(73)	(109)
Current Assets	1,507							1,341									1,507	1,341
Property, Plant and Equipment, net	8,842							8,596									8,842	8,596
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures	0							0									0	0
Noncurrent Assets	2,245							2,481									2,245	2,481
Total Assets	12,594							12,418									12,594	12,418
Current Liabilities	842							1,435									842	1,435
Noncurrent Liabilities	3,001							2,880									3,001	2,880
Total Long-Term Debt	2,791							2,136									2,791	2,136
Member's Equity	5,960							5,967									5,960	5,967
TOTAL LIABILITIES AND CAPITALIZATION	12,594							12,418									12,594	12,418
Power Senior Notes [Member] | Guarantor Subsidiaries [Member]
Guarantees of Debt [Line Items]
Operating Revenues																	4,078	3,821	3,809
Operating Expenses																	3,460	4,159	3,796
Operating Income (Loss)																	618	(338)	13
Equity Earnings (Losses) of Subsidiaries																	(28)	60	(3)
Net Gains (Losses) on Trust Investments																	(139)	122	(7)
Other Income (Deductions)																	166	91	60
Non-Operating Pension and Other Postretirement Plan Credits (Costs)																	13	8	(4)
Interest Expense																	(96)	(49)	(40)
Income Tax Benefit (Expense)																	(143)	588	(11)
Net Income																	391	482	8
Comprehensive Income (Loss), Net of Tax, Attributable to Parent																	379	529	50
Net Cash Provided By (Used In) Operating Activities																	1,007	1,185	1,442
Net Cash Provided By (Used In) Investing Activities																	(1,034)	(448)	(707)
Net Cash Provided By (Used In) Financing Activities																	27	(736)	(736)
Current Assets	1,479							1,500									1,479	1,500
Property, Plant and Equipment, net	4,971							5,778									4,971	5,778
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures	1,107							404									1,107	404
Noncurrent Assets	2,109							2,349									2,109	2,349
Total Assets	9,666							10,031									9,666	10,031
Current Liabilities	2,971							3,586									2,971	3,586
Noncurrent Liabilities	1,996							1,966									1,996	1,966
Total Long-Term Debt	0							0									0	0
Member's Equity	4,699							4,479									4,699	4,479
TOTAL LIABILITIES AND CAPITALIZATION	9,666							10,031									9,666	10,031
Power Senior Notes [Member] | Non-Guarantor Subsidiaries [Member]
Guarantees of Debt [Line Items]
Operating Revenues																	224	174	173
Operating Expenses																	232	195	161
Operating Income (Loss)																	(8)	(21)	12
Equity Earnings (Losses) of Subsidiaries																	15	14	11
Net Gains (Losses) on Trust Investments																	0	0	0
Other Income (Deductions)																	0	2	0
Non-Operating Pension and Other Postretirement Plan Credits (Costs)																	2	0	0
Interest Expense																	(30)	(17)	(18)
Income Tax Benefit (Expense)																	8	167	20
Net Income																	(13)	145	25
Comprehensive Income (Loss), Net of Tax, Attributable to Parent																	(13)	145	25
Net Cash Provided By (Used In) Operating Activities																	42	238	323
Net Cash Provided By (Used In) Investing Activities																	(406)	(525)	(789)
Net Cash Provided By (Used In) Financing Activities																	354	307	466
Current Assets	304							200									304	200
Property, Plant and Equipment, net	3,822							2,764									3,822	2,764
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures	0							0									0	0
Noncurrent Assets	101							110									101	110
Total Assets	4,227							3,074									4,227	3,074
Current Liabilities	2,027							1,846									2,027	1,846
Noncurrent Liabilities	730							459									730	459
Total Long-Term Debt	0							0									0	0
Member's Equity	1,470							769									1,470	769
TOTAL LIABILITIES AND CAPITALIZATION	4,227							3,074									4,227	3,074
Power Senior Notes [Member] | Power Parent [Member]
Guarantees of Debt [Line Items]
Operating Revenues																	0	0	0
Operating Expenses																	14	8	8
Operating Income (Loss)																	(14)	(8)	(8)
Equity Earnings (Losses) of Subsidiaries																	406	567	36
Net Gains (Losses) on Trust Investments																	(1)	3	1
Other Income (Deductions)																	135	71	52
Non-Operating Pension and Other Postretirement Plan Credits (Costs)																	0	0	0
Interest Expense																	(230)	(128)	(115)
Income Tax Benefit (Expense)																	69	(26)	52
Net Income																	365	479	18
Comprehensive Income (Loss), Net of Tax, Attributable to Parent																	393	518	47
Net Cash Provided By (Used In) Operating Activities																	(74)	(42)	97
Net Cash Provided By (Used In) Investing Activities																	(402)	506	60
Net Cash Provided By (Used In) Financing Activities																	476	(464)	(157)
Current Assets	4,317							4,327									4,317	4,327
Property, Plant and Equipment, net	49							54									49	54
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures	5,062							4,844									5,062	4,844
Noncurrent Assets	273							100									273	100
Total Assets	9,701							9,325									9,701	9,325
Current Liabilities	437							689									437	689
Noncurrent Liabilities	513							533									513	533
Total Long-Term Debt	2,791							2,136									2,791	2,136
Member's Equity	5,960							5,967									5,960	5,967
TOTAL LIABILITIES AND CAPITALIZATION	9,701							9,325									9,701	9,325
Consolidation, Eliminations [Member] | Power Senior Notes [Member]
Guarantees of Debt [Line Items]
Operating Revenues																	(156)	(135)	(121)
Operating Expenses																	(156)	(135)	(121)
Operating Income (Loss)																	0	0	0
Equity Earnings (Losses) of Subsidiaries																	(378)	(627)	(33)
Net Gains (Losses) on Trust Investments																	0	0	0
Other Income (Deductions)																	(280)	(144)	(89)
Non-Operating Pension and Other Postretirement Plan Credits (Costs)																	0	0	0
Interest Expense																	280	144	89
Income Tax Benefit (Expense)																	0	0	0
Net Income																	(378)	(627)	(33)
Comprehensive Income (Loss), Net of Tax, Attributable to Parent																	(366)	(674)	(75)
Net Cash Provided By (Used In) Operating Activities																	109	(55)	(607)
Net Cash Provided By (Used In) Investing Activities																	791	(765)	289
Net Cash Provided By (Used In) Financing Activities																	(900)	820	$ 318
Current Assets	(4,593)							(4,686)									(4,593)	(4,686)
Property, Plant and Equipment, net	0							0									0	0
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures	(6,169)							(5,248)									(6,169)	(5,248)
Noncurrent Assets	(238)							(78)									(238)	(78)
Total Assets	(11,000)							(10,012)									(11,000)	(10,012)
Current Liabilities	(4,593)							(4,686)									(4,593)	(4,686)
Noncurrent Liabilities	(238)							(78)									(238)	(78)
Total Long-Term Debt	0							0									0	0
Member's Equity	(6,169)							(5,248)									(6,169)	(5,248)
TOTAL LIABILITIES AND CAPITALIZATION	$ (11,000)							$ (10,012)									$ (11,000)	$ (10,012)
[1]	The increases in Operating Income at PSEG consolidated and Power in the first and second quarters of 2018 as compared to the same quarters in 2017 were primarily due to higher costs in 2017 related to closing the coal/gas Hudson and Mercer units, which were fully depreciated as of June 1, 2017. The increases in Operating Income at PSEG consolidated and Power in the fourth quarter 2018 as compared to the same quarter in 2017 were primarily due to lower MTM losses and a gain on the sale of the Hudson and Mercer units.The decreases in Net Income at PSEG consolidated and Power in the fourth quarter 2018 as compared to the same quarter in 2017 also reflected the impact of the one-time benefit recorded in December 2017 as a result of the remeasurement of deferred tax balances and the inclusion in 2018 of net unrealized losses on equity investments in the NDT Fund in accordance with new accounting guidance.

Valuation And Qualifying Acco_2

Valuation And Qualifying Accounts (Schedule Of Valuation And Qualifying Accounts) (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2018		Dec. 31, 2017		Dec. 31, 2016
Allowance For Doubtful Accounts [Member]
SEC Schedule, 12-09, Valuation and Qualifying Accounts Disclosure [Line Items]
Balance at Beginning of Period		$ 59		$ 68		$ 67
Additions, Charged to cost and expenses		91		76		85
Additions, Charged to other accounts-describe		0		0		0
Deductions-describe	[1]	87		85		84
Balance at End of Period		63		59		68
Materials And Supplies Valuation Reserve [Member]
SEC Schedule, 12-09, Valuation and Qualifying Accounts Disclosure [Line Items]
Balance at Beginning of Period		7		37		11
Additions, Charged to cost and expenses		4		2		32
Additions, Charged to other accounts-describe		0		0		0
Deductions-describe		2	[2]	32	[3]	6	[2]
Balance at End of Period		9		7		37
PSE&G [Member] | Allowance For Doubtful Accounts [Member]
SEC Schedule, 12-09, Valuation and Qualifying Accounts Disclosure [Line Items]
Balance at Beginning of Period		59		68		67
Additions, Charged to cost and expenses		91		76		85
Additions, Charged to other accounts-describe		0		0		0
Deductions-describe	[4]	87		85		84
Balance at End of Period		63		59		68
PSE&G [Member] | Materials And Supplies Valuation Reserve [Member]
SEC Schedule, 12-09, Valuation and Qualifying Accounts Disclosure [Line Items]
Balance at Beginning of Period		0		0		1
Additions, Charged to cost and expenses		2		0		0
Additions, Charged to other accounts-describe		0		0		0
Deductions-describe		0		0		1	[5]
Balance at End of Period		2		0		0
Power [Member] | Materials And Supplies Valuation Reserve [Member]
SEC Schedule, 12-09, Valuation and Qualifying Accounts Disclosure [Line Items]
Balance at Beginning of Period		7		37		10
Additions, Charged to cost and expenses		2		2		32
Additions, Charged to other accounts-describe		0		0		0
Deductions-describe		2	[6]	32	[7]	5	[6]
Balance at End of Period		$ 7		$ 7		$ 37
[1]	Accounts Receivable written off.
[2]	Reduce reserve to appropriate level and to remove obsolete inventory.
[3]	Hudson and Mercer inventory written off.
[4]	Accounts Receivable written off.
[5]	Reduce reserve to appropriate level and to remove obsolete inventory.
[6]	Reduce reserve to appropriate level and to remove obsolete inventory.
[7]	Hudson and Mercer inventory written off.